QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2012

OR

¨

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from __________________ to __________________

Commission file number: 1-15467

VECTREN CORPORATION

(Exact name of registrant as specified in its charter)

INDIANA

35-2086905

(State or other jurisdiction of incorporation or organization)

(IRS Employer Identification No.)

One Vectren Square, Evansville, IN 47708

(Address of principal executive offices)

(Zip Code)

812-491-4000

(Registrant's telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. ý Yes ¨ No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

ý Yes ¨ No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

¨ Yes ý No

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date.

Common Stock- Without Par Value

82,131,807

October 31, 2012

Class

Number of Shares

Date

Access to Information

Vectren Corporation makes available all SEC filings and recent annual reports free of charge through its website at www.vectren.com as soon as reasonably practicable after electronically filing or furnishing the reports to the SEC, or by request, directed to Investor Relations at the mailing address, phone number, or email address that follows:

The accompanying notes are an integral part of these consolidated condensed financial statements.

3

VECTREN CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED CONDENSED BALANCE SHEETS

(Unaudited – In millions)

September 30, 2012

December 31, 2011

LIABILITIES & SHAREHOLDERS' EQUITY

Current Liabilities

Accounts payable

$

159.1

$

185.8

Accounts payable to affiliated companies

15.4

36.8

Refundable fuel & natural gas costs

1.1

—

Accrued liabilities

159.3

181.1

Short-term borrowings

316.2

227.1

Current maturities of long-term debt

131.5

62.7

Total current liabilities

782.6

693.5

Long-term Debt - Net of Current Maturities

1,453.7

1,559.6

Deferred Income Taxes & Other Liabilities

Deferred income taxes

629.3

575.7

Regulatory liabilities

359.1

345.2

Deferred credits & other liabilities

205.3

239.4

Total deferred credits & other liabilities

1,193.7

1,160.3

Commitments & Contingencies (Notes 7, 9-12)

Common Shareholders' Equity

Common stock (no par value) – issued & outstanding

82.1 & 81.9 shares, respectively

698.7

692.6

Retained earnings

816.2

786.2

Accumulated other comprehensive income (loss)

(8.7

)

(13.3

)

Total common shareholders' equity

1,506.2

1,465.5

TOTAL LIABILITIES & SHAREHOLDERS' EQUITY

$

4,936.2

$

4,878.9

The accompanying notes are an integral part of these consolidated condensed financial statements.

4

VECTREN CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED CONDENSED STATEMENTS OF INCOME

(Unaudited – in millions, except per share amounts)

Three Months Ended

Nine Months Ended

September 30,

September 30,

2012

2011

2012

2011

OPERATING REVENUES

Gas utility

$

100.2

$

102.1

$

508.5

$

592.8

Electric utility

167.9

186.7

456.6

492.4

Nonutility

245.4

250.6

623.6

612.6

Total operating revenues

513.5

539.4

1,588.7

1,697.8

OPERATING EXPENSES

Cost of gas sold

28.1

30.5

197.0

274.4

Cost of fuel & purchased power

52.9

67.1

144.6

186.9

Cost of nonutility revenues

81.0

93.0

198.1

266.6

Other operating

195.6

180.6

557.2

485.5

Depreciation & amortization

61.9

61.7

188.9

182.0

Taxes other than income taxes

12.4

12.4

41.2

43.4

Total operating expenses

431.9

445.3

1,327.0

1,438.8

OPERATING INCOME

81.6

94.1

261.7

259.0

OTHER INCOME (EXPENSE)

Equity in (losses) of unconsolidated affiliates

(3.6

)

(11.7

)

(17.8

)

(34.6

)

Other income – net

3.3

0.7

7.8

5.9

Total other income (expense)

(0.3

)

(11.0

)

(10.0

)

(28.7

)

INTEREST EXPENSE

23.9

27.1

71.8

80.7

INCOME BEFORE INCOME TAXES

57.4

56.0

179.9

149.6

INCOME TAXES

18.1

20.7

63.7

54.6

NET INCOME

$

39.3

$

35.3

$

116.2

$

95.0

AVERAGE COMMON SHARES OUTSTANDING

82.1

81.8

82.0

81.7

DILUTED COMMON SHARES OUTSTANDING

82.1

81.9

82.1

81.8

EARNINGS PER SHARE OF COMMON STOCK:

BASIC

$

0.48

$

0.43

$

1.42

$

1.16

DILUTED

$

0.48

$

0.43

$

1.42

$

1.16

DIVIDENDS DECLARED PER SHARE OF COMMON STOCK

$

0.350

$

0.345

$

1.050

$

1.035

The accompanying notes are an integral part of these consolidated condensed financial statements.

5

VECTREN CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED CONDENSED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited – in millions)

Three Months Ended

Nine Months Ended

September 30,

September 30,

2012

2011

2012

2011

Net income

$

39.3

$

35.3

$

116.2

$

95.0

Other comprehensive income (loss), before tax:

Comprehensive income (loss) of unconsolidated affiliates

0.7

(5.2

)

6.7

(1.8

)

Remeasurement of postretirement benefit obligation

—

—

1.1

—

Cash flow hedges

—

0.6

—

(1.8

)

Other comprehensive income (loss), before tax

0.7

(4.6

)

7.8

(3.6

)

Income taxes related to items of other comprehensive income

(0.3

)

1.8

(3.2

)

1.4

Other comprehensive income (loss), net of tax

0.4

(2.8

)

4.6

(2.2

)

Total comprehensive income

$

39.7

$

32.5

$

120.8

$

92.8

The accompanying notes are an integral part of these consolidated condensed financial statements.

6

VECTREN CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited – In millions)

Nine Months Ended

September 30,

2012

2011

CASH FLOWS FROM OPERATING ACTIVITIES

Net income

$

116.2

$

95.0

Adjustments to reconcile net income to cash from operating activities:

Depreciation & amortization

188.9

182.0

Deferred income taxes & investment tax credits

52.6

56.5

Equity in losses of unconsolidated affiliates

17.8

34.6

Provision for uncollectible accounts

6.0

9.1

Expense portion of pension & postretirement benefit cost

6.8

6.8

Other non-cash charges - net

5.5

9.5

Changes in working capital accounts:

Accounts receivable & accrued unbilled revenues

40.5

68.6

Inventories

(8.8

)

(20.2

)

Recoverable/refundable fuel & natural gas costs

(7.9

)

(8.1

)

Prepayments & other current assets

5.7

(1.0

)

Accounts payable, including to affiliated companies

(50.8

)

(83.8

)

Accrued liabilities

(22.0

)

(3.4

)

Unconsolidated affiliate dividends

0.1

0.1

Employer contributions to pension & postretirement plans

(16.1

)

(37.2

)

Changes in noncurrent assets

(33.7

)

(8.4

)

Changes in noncurrent liabilities

(7.0

)

(8.6

)

Net cash flows from operating activities

293.8

291.5

CASH FLOWS FROM FINANCING ACTIVITIES

Proceeds from:

Long-term debt, net of issuance costs

99.5

—

Dividend reinvestment plan & other common stock issuances

5.6

5.2

Requirements for:

Dividends on common stock

(86.1

)

(84.6

)

Retirement of long-term debt

(37.4

)

(2.2

)

Other financing activities

—

(1.4

)

Net change in short-term borrowings

(10.9

)

98.1

Net cash flows from financing activities

(29.3

)

15.1

CASH FLOWS FROM INVESTING ACTIVITIES

Proceeds from:

Unconsolidated affiliate distributions

0.2

0.5

Other collections

8.9

1.0

Requirements for:

Capital expenditures, excluding AFUDC equity

(274.9

)

(227.8

)

Business acquisition, net of cash acquired

—

(83.4

)

Other investments

(0.3

)

(0.9

)

Net cash flows from investing activities

(266.1

)

(310.6

)

Net change in cash & cash equivalents

(1.6

)

(4.0

)

Cash & cash equivalents at beginning of period

8.6

10.4

Cash & cash equivalents at end of period

$

7.0

$

6.4

The accompanying notes are an integral part of these consolidated condensed financial statements.

7

VECTREN CORPORATION AND SUBSIDIARY COMPANIES

NOTES TO THE CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

(UNAUDITED)

1.

Organization and Nature of Operations

Vectren Corporation (the Company or Vectren), an Indiana corporation, is an energy holding company headquartered in Evansville, Indiana. The Company’s wholly owned subsidiary, Vectren Utility Holdings, Inc. (Utility Holdings), serves as the intermediate holding company for three public utilities: Indiana Gas Company, Inc. (Indiana Gas or Vectren North), Southern Indiana Gas and Electric Company (SIGECO or Vectren South), and Vectren Energy Delivery of Ohio, Inc. (VEDO). Utility Holdings also has other assets that provide information technology and other services to the three utilities. Utility Holdings’ consolidated operations are collectively referred to as the Utility Group. Both Vectren and Utility Holdings are holding companies as defined by the Energy Policy Act of 2005 (Energy Act). Vectren was incorporated under the laws of Indiana on June 10, 1999.

Indiana Gas provides energy delivery services to approximately 564,000 natural gas customers located in central and southern Indiana. SIGECO provides energy delivery services to approximately 142,000 electric customers and approximately 110,000 gas customers located near Evansville in southwestern Indiana. SIGECO also owns and operates electric generation assets to serve its electric customers and optimizes those assets in the wholesale power market. Indiana Gas and SIGECO generally do business as Vectren Energy Delivery of Indiana. VEDO provides energy delivery services to approximately 310,000 natural gas customers located near Dayton in west-central Ohio.

The Company, through Vectren Enterprises, Inc. (Enterprises), is involved in nonutility activities in four primary business areas: Infrastructure Services, Energy Services, Coal Mining, and Energy Marketing. Infrastructure Services provides underground construction and repair services. Energy Services provides performance contracting and renewable energy services. Coal Mining mines and sells coal. Energy Marketing markets and supplies natural gas and provides energy management services. Enterprises also has other legacy businesses that have invested in energy-related opportunities and services, real estate, and leveraged leases, among other investments. All of the above are collectively referred to as the Nonutility Group. Enterprises supports the Company’s regulated utilities pursuant to service contracts by providing natural gas supply services, coal, and infrastructure services.

2.

Basis of Presentation

The interim consolidated condensed financial statements included in this report have been prepared by the Company, without audit, as provided in the rules and regulations of the Securities and Exchange Commission and include a review of subsequent events through the date the financial statements were issued. Certain information and note disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States have been omitted as provided in such rules and regulations. The information in this report reflects all adjustments which are, in the opinion of management, necessary to fairly state the interim periods presented, inclusive of adjustments that are normal and recurring in nature. These consolidated condensed financial statements and related notes should be read in conjunction with the Company’s audited annual consolidated financial statements for the year ended December 31, 2011, filed with the Securities and Exchange Commission on February 16, 2012, on Form 10-K. Because of the seasonal nature of the Company’s operations, the results shown on a quarterly basis are not necessarily indicative of annual results.

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates.

8

3.

Earnings Per Share

The Company uses the two class method to calculate earnings per share (EPS). The two class method is an earnings allocation formula that treats a participating security as having rights to earnings that otherwise would have been available to common shareholders. Under the two class method, earnings for a period are allocated between common shareholders and participating security holders based on their respective rights to receive dividends as if all undistributed book earnings for the period were distributed. Basic EPS is computed by dividing net income attributable to only the common shareholders by the weighted-average number of common shares outstanding for the period. Diluted EPS includes the impact of stock options and other equity based instruments to the extent the effect is dilutive. The following table illustrates the basic and dilutive EPS calculations for the periods presented in these financial statements.

Three Months Ended

Nine Months Ended

September 30,

September 30,

(In millions, except per share data)

2012

2011

2012

2011

Numerator:

Reported net income (Numerator for Basic and Diluted EPS)

$

39.3

$

35.3

$

116.2

$

95.0

Denominator:

Weighted average common shares outstanding

(Denominator for Basic and Diluted EPS)

$

82.1

$

81.8

$

82.0

$

81.7

Conversion of share based compensation arrangements

—

0.1

0.1

0.1

Adjusted weighted average shares outstanding and

assumed conversions outstanding (Diluted EPS)

$

82.1

$

81.9

$

82.1

$

81.8

Basic EPS

$

0.48

$

0.43

$

1.42

$

1.16

Diluted EPS

$

0.48

$

0.43

$

1.42

$

1.16

For the three and nine months endedSeptember 30, 2011, options to purchase 1,920 additional shares of the Company’s common stock were outstanding, but were not included in the computation of diluted EPS because their effect would be antidilutive. The exercise prices for these options were $27.15 for the three and nine months endedSeptember 30, 2011. For the three and nine months endedSeptember 30, 2012 , all options were dilutive.

4.

Excise and Utility Receipts Taxes

Excise taxes and a portion of utility receipts taxes are included in rates charged to customers. Accordingly, the Company records these taxes received, which totaled $4.8 million and $5.0 million in the three months endedSeptember 30, 2012 and 2011, respectively, as a component of operating revenues. During the nine months endedSeptember 30, 2012 and 2011, these taxes totaled $19.1 million and $21.6 million, respectively. Expenses associated with excise and utility receipts taxes are recorded as a component of Taxes other than income taxes.

5.

Retirement Plans & Other Postretirement Benefits

The Company maintains three qualified defined benefit pension plans, a nonqualified supplemental executive retirement plan (SERP), and provides other postretirement benefits. The defined benefit pension plan and other postretirement benefits, which cover eligible full-time regular employees, are primarily noncontributory. The postretirement health care plan is self-insured and the life insurance plan is fully insured. The qualified pension plans and the SERP plan are aggregated under the heading “Pension Benefits.” Other postretirement benefit obligations are aggregated under the heading “Other Benefits.”

Postretirement Benefit Change

On May 31, 2012, the Company notified participants receiving postretirement health care benefits that effective September 1, 2012 the Company will no longer offer postretirement health coverage for participants 65 and older. Rather, the Company will provide a subsidy to plan participants to purchase health coverage through a private Medicare exchange. This change in benefits is intended to provide a comparable benefit at a reduced cost made possible by current market pricing. Since this

9

change in benefits is a significant event pursuant to GAAP, the Company remeasured its postretirement benefit obligations as of June 1, 2012. The change in benefits, net of the impacts associated with remeasuring the benefit obligations using a lower discount rate, resulted in a $23 million reduction in the postretirement liability. The Company lowered the discount rate used to remeasure its postretirement benefit obligations from 4.78 percent utilized on December 31, 2011 to 3.93 percent due to lower benchmark interest rates that approximate the expected duration of the Company's obligations. Substantially all of the amount was recorded as a reduction to Regulatory Assets, as the Company's retirement costs primarily relate to its regulated utilities.

Net Periodic Benefit Costs

A summary of the components of net periodic benefit cost follows:

Three Months Ended

September 30,

Pension Benefits

Other Benefits

(In millions)

2012

2011

2012

2011

Service cost

$

1.9

$

1.7

$

0.2

$

0.1

Interest cost

3.8

3.9

0.6

1.1

Expected return on plan assets

(5.2

)

(5.3

)

—

—

Amortization of prior service cost

0.4

0.5

(1.0

)

(0.2

)

Amortization of transitional obligation

—

—

—

0.2

Amortization of actuarial loss

1.7

1.0

0.2

0.2

Net periodic benefit cost

$

2.6

$

1.8

$

—

$

1.4

Nine Months Ended

September 30,

Pension Benefits

Other Benefits

(In millions)

2012

2011

2012

2011

Service cost

$

5.7

$

5.2

$

0.4

$

0.4

Interest cost

11.6

11.9

2.3

3.2

Expected return on plan assets

(15.8

)

(15.9

)

—

—

Amortization of prior service cost

1.2

1.3

(1.6

)

(0.6

)

Amortization of transitional obligation

—

—

0.5

0.8

Amortization of actuarial loss

5.1

2.9

0.5

0.5

Net periodic benefit cost

$

7.8

$

5.4

$

2.1

$

4.3

Employer Contributions to Qualified Pension Plans

Currently, the Company expects to contribute approximately $15.0 million to its pension plan trusts for 2012. During the nine months endedSeptember 30, 2012, contributions of $11.1 million have been made.

6.

Supplemental Cash Flow Information

As of September 30, 2012 and December 31, 2011, the Company has accruals related to utility and nonutility plant purchases totaling approximately $8.8 million and $15.9 million, respectively.

7. ProLiance Holdings, LLC

ProLiance Holdings, LLC (ProLiance), a nonutility energy marketing affiliate of Vectren and Citizens Energy Group (Citizens), provides services to a broad range of municipalities, utilities, industrial operations, schools, and healthcare institutions located throughout the Midwest and Southeast United States. ProLiance’s customers include, among others, Vectren’s Indiana utilities as well as Citizens’ utilities. ProLiance’s primary businesses include gas marketing, gas portfolio optimization, and other portfolio and energy management services. Consistent with its ownership percentage, Vectren is allocated 61 percent of ProLiance’s profits and losses; however, governance and voting rights remain at 50 percent for each member; and therefore, the Company accounts for its investment in ProLiance using the equity method of accounting.

10

Summarized Financial Information

Three Months Ended

Nine Months Ended

September 30,

September 30,

(In millions)

2012

2011

2012

2011

Summarized statement of income information:

Revenues

$

207.5

$

283.0

$

735.3

$

1,074.8

Operating (loss)

(4.3

)

(19.4

)

(25.5

)

(56.7

)

ProLiance's net (loss)

(4.8

)

(19.5

)

(28.0

)

(57.2

)

As of

September 30,

December 31,

(In millions)

2012

2011

Summarized balance sheet information:

Current assets

$

248.0

$

381.9

Noncurrent assets

55.2

56.1

Current liabilities

181.4

298.5

Noncurrent liabilities

0.4

0.7

Members' equity

133.5

161.5

Accumulated other comprehensive (loss)

(15.1

)

(26.0

)

Noncontrolling interest

3.0

3.3

Vectren records its 61 percent share of ProLiance’s results in Equity in (losses) of unconsolidated affiliates. Interest expense and income taxes associated with the investment are recorded separately within the statements of income in those line items. As of September 30, 2012 and December 31, 2011, the Company’s investment balance, inclusive of its share of ProLiance’s accumulated other comprehensive loss and certain historical book basis differences, is $75.0 million and $85.4 million, respectively. The amounts recorded to Equity in (losses) of unconsolidated affiliates related to ProLiance’s operations totaled a pre-tax loss of $3.0 million and $11.9 million for the three months endedSeptember 30, 2012 and 2011, respectively, and for the nine months endedSeptember 30, 2012 and 2011, such pre-tax losses totaled $17.1 million and $34.9 million.

Investment in Liberty Gas Storage

Liberty Gas Storage, LLC (Liberty), a joint venture between a subsidiary of ProLiance and a subsidiary of Sempra Energy (SE), is a development project for salt-cavern natural gas storage facilities. ProLiance is the minority member with a 25 percent interest, which it accounts for using the equity method. The project was expected to include 17 Bcf of capacity in its North site, and an additional capacity of at least 17 Bcf at the South site. The South site also has the potential for further expansion. The Liberty pipeline system is currently connected with several interstate pipelines, including the Cameron Interstate Pipeline operated by Sempra U.S. Gas & Power, and will connect area LNG regasification terminals to an interstate natural gas transmission system and storage facilities.

In late 2008, the project at the North site was halted due to subsurface and well-completion problems, resulting in an impairment charge related to the North site being recorded in 2009. ProLiance’s ability to meet the needs of its customers has not been, nor does it expect it to be, impacted. Approximately 12 Bcf of the storage at the South site, which comprises three of the four FERC certified caverns, is fully completed and tested. As a result of the issues encountered at the North site, Liberty requested and the FERC approved the separation of the North site from the South site. As of September 30, 2012 and December 31, 2011, ProLiance’s investment in Liberty approximated $34.9 million and $35.1 million, respectively.

11

Liberty received a Demand for Arbitration from Williams Midstream Natural Gas Liquids, Inc. (“Williams”) on February 8, 2011 related to a Sublease Agreement (“Sublease”) between Liberty and Williams at the North site. Williams alleges that Liberty was negligent in its attempt to convert certain salt caverns to natural gas storage and thereby damaged the caverns. Williams alleges damages of $56.7 million. Liberty believes that it has complied with all of its obligations to Williams, including properly terminating the Sublease. Liberty intends to vigorously defend itself and has asserted counterclaims substantially in excess of the amounts asserted by Williams. As such, as of September 30, 2012, ProLiance has no material reserve recorded related to this matter and this litigation has not materially impacted ProLiance's results of operations or statement of financial position.

Transactions with ProLiance

Purchases of natural gas from ProLiance for resale and for injections into storage for the three months ended September 30, 2012 and 2011 totaled $57.2 million and $80.5 million, respectively, and for the nine months endedSeptember 30, 2012 and 2011, totaled $186.9 million and $281.6 million. Amounts owed to ProLiance at September 30, 2012 and December 31, 2011, for those purchases were $15.4 million and $36.8 million, respectively, and are included in Accounts payable to affiliated companies in the Consolidated Condensed Balance Sheets. Vectren received regulatory approval on April 25, 2006, from the IURC for ProLiance to provide natural gas supply services to the Company’s Indiana utilities through March 2011. On March 17, 2011, an order was received from the IURC providing for ProLiance’s continued provision of gas supply services to the Company’s Indiana utilities and Citizens Energy Group's utilities through March 2016. Amounts charged by ProLiance for gas supply services are established by supply agreements with each utility.

8. Financing Activities

Vectren Capital Term Loan

On November 1, 2012, Vectren Capital entered into a $100 millionthree year term loan agreement. Loans under the term loan agreement bear interest at either a Eurodollar rate or base rate plus a fixed adder, as defined in the loan agreement, based on the Company's credit rating. The proceeds from this debt transaction were used to repay short-term borrowings outstanding under Vectren Capital's credit facility. The loan agreement is guaranteed by Vectren Corporation and includes customary representations, warranties and covenants, including a leverage covenant consistent with leverage covenants contained in other Vectren Capital borrowing arrangements.

VUHI Debt Issuance

On February 1, 2012, Utility Holdings issued $100 million of senior unsecured notes at an interest rate of 5.00 percent per annum and with a maturity date of February 3, 2042. The notes were sold to various institutional investors pursuant to a private placement note purchase agreement executed in November 2011 with a delayed draw feature. These senior notes are unsecured and jointly and severally guaranteed by Utility Holdings’ regulated utility subsidiaries, SIGECO, Indiana Gas, and VEDO. The proceeds from the sale of the notes, net of issuance costs, totaled approximately $99.5 million. These notes have no sinking fund requirements and interest payments are due semi-annually. These notes contain customary representations, warranties and covenants, including a leverage covenant consistent with leverage covenants contained in other Utility Holdings’ borrowing arrangements. As of December 31, 2011, the Company had reclassified $100 million of short-term borrowings as long-term debt to reflect those borrowings were refinanced with the proceeds received.

9.

Commitments & Contingencies

Corporate Guarantees

The Company issues parent level guarantees to certain vendors and customers of its wholly owned subsidiaries and unconsolidated affiliates. These guarantees do not represent incremental consolidated obligations; rather, they represent parental guarantees of subsidiary and unconsolidated affiliate obligations in order to allow those subsidiaries and affiliates the flexibility to conduct business without posting other forms of collateral. At September 30, 2012, parent level guarantees support a maximum of $25 million of ESG’s performance contracting commitments and warranty obligations and $28 million of other project guarantees. The broader scope of ESG’s performance contracting obligations, including those not guaranteed by the parent company, are described below. In addition, the parent company has approximately $25 million of other guarantees outstanding supporting other consolidated subsidiary operations, of which $19 million represent letters of credit supporting other nonutility operations. Guarantees issued and outstanding on behalf of unconsolidated affiliates approximated $3 million at September 30, 2012. These guarantees relate primarily to arrangements between ProLiance and various natural gas pipeline

12

operators. The Company has not been called upon to satisfy any obligations pursuant to these parental guarantees and has accrued no significant liabilities related to these guarantees.

Performance Guarantees & Product Warranties

In the normal course of business, wholly owned subsidiaries, including ESG, issue performance bonds or other forms of assurance that commit them to timely install infrastructure, operate facilities, pay vendors or subcontractors, and/or support warranty obligations. Based on a history of meeting performance obligations and installed products operating effectively, no significant liability or cost has been recognized for the periods presented.

Specific to ESG, in its role as a general contractor in the performance contracting industry, at September 30, 2012, there are 68 open surety bonds supporting future performance. The average face amount of these obligations is $4.9 million, and the largest obligation has a face amount of $57.3 million. The maximum exposure from these obligations is limited by the level of work already completed and guarantees issued to ESG by various subcontractors. At September 30, 2012, approximately 56 percent of work was completed on projects with open surety bonds. A significant portion of these open surety bonds will be released within one year. In instances where ESG operates facilities, project guarantees extend over a longer period. In addition to its performance obligations, ESG also warrants the functionality of certain installed infrastructure generally for one year and the associated energy savings over a specified number of years. The Company has no significant accruals for these warranty obligations as of September 30, 2012.

Legal & Regulatory Proceedings

The Company is party to various legal proceedings, audits, and reviews by taxing authorities and other government agencies arising in the normal course of business. In the opinion of management, there are no legal proceedings or other regulatory reviews or audits pending against the Company that are likely to have a material adverse effect on its financial position, results of operations or cash flows.

10.

Legislative Matters

Pipeline Safety Law

On January 3, 2012 the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 was signed into law. This new law, which reauthorizes federal pipeline safety programs through fiscal year 2015, provides for enhanced safety, reliability and environmental protection in the transportation of energy products by pipeline. The new law increases federal enforcement authority, grants the federal government expanded authority over pipeline safety, provides for new safety regulations and standards, and authorizes or requires the completion of several pipeline safety-related studies. The DOT is required to promulgate a number of new regulatory requirements. Those regulations may eventually lead to further regulatory or statutory requirements.

The Company continues to study the impact of the new law and potential new regulations associated with its implementation. At this time, compliance costs and other effects associated with the increased pipeline safety regulations remain uncertain. However, the new law is expected to result in further investment in pipeline inspections, and where necessary, additional modernization of pipeline infrastructure; and therefore, result in both increased levels of operating expenses and capital expenditures associated with the Company’s natural gas distribution businesses. Operating expenses associated with expanded compliance requirements may grow to approximately $9 million annually, with $6 million attributable to the Indiana operations. Related to the Indiana operations, the Company expects to seek recovery under Senate Bill 251 referenced below, or such costs may be recoverable through current tracking mechanisms. Capital investments, driven by the pipeline safety regulations, associated with the Company’s gas utilities are expected to be significant. The Company expects to seek recovery of capital investments associated with complying with these federal mandates in accordance with Senate Bill 251 in Indiana and House Bill 95 or other currently authorized recovery mechanisms in Ohio (referenced below).

Indiana Senate Bill 251

In April 2011, Senate Bill 251 was signed into law. While the bill is broad in scope, it allows for cost recovery outside of a base rate proceeding for federal government mandated projects and provides for a voluntary clean energy portfolio standard.

13

The law applies to both gas and electric utility operations and provides a framework to recover 80 percent of federally mandated operating costs and capital investments through a periodic rate adjustment mechanism outside of a general rate case. Such costs include depreciation, operating and other costs. Construction costs receive a return on investment. The remaining 20 percent of those costs and capital investments are to be deferred for recovery in the utility’s next general rate case. The Company is currently evaluating the impact this law may have on its operations, including applicability to expenditures associated with the integrity, safety, and reliable operation of natural gas pipelines and facilities; ash disposal; water regulations; and air pollution control, including greenhouse gas emissions, among other federally mandated projects and potential projects.

Ohio House Bill 95

In June 2011, Ohio House Bill 95 was signed into law. The law adjusts, among other things, the manner in which gas utilities file for rate changes, including the implementation of base rate changes, alternative rate plans, and automatic rate adjustment mechanisms. Outside of a base rate proceeding, the legislation permits a natural gas company to apply for recovery of a capital expenditure program for infrastructure expansion, upgrade, or replacement; installation, upgrade, or replacement of information technology systems; or any program necessary to comply with government regulation. Once such application is approved, the legislation authorizes deferral of program costs, such as depreciation, property taxes, and debt-related carrying costs. On February 3, 2012, the Company initiated a filing under House Bill 95. This filing requests accounting authority to defer depreciation, debt-related post in service carrying costs and property taxes for its fifteen month capital expenditure program ending on December 31, 2012. The capital expenditure program totals $23.5 million and includes infrastructure expansion and improvements not covered by the Company’s distribution replacement rider as well as expenditures necessary to comply with PUCO rules, regulations and orders. The Company’s approach is consistent with approaches made by other Ohio utilities. A procedural schedule associated with the filing has been set and all respective responses have been submitted. It is anticipated the PUCO will act on the Company’s filing later this year.

11.

Environmental Matters

Air Quality

Clean Air Interstate Rule / Cross-State Air Pollution Rule

In July 2011, the EPA finalized the Cross-State Air Pollution Rule (CSAPR). CSAPR was the EPA’s response to the US Court of Appeals for the District of Columbia’s (the Court) remand of the Clean Air Interstate Rule (CAIR). CAIR was originally established in 2005 as an allowance cap and trade program that required reductions from coal-burning power plants for NOx emissions beginning January 1, 2009 and SO2 emissions beginning January 1, 2010, with a second phase of reductions in 2015. In an effort to address the Court’s finding that CAIR did not adequately ensure attainment of pollutants in certain downwind states due to unlimited trading of SO2 and NOx allowances, CSAPR reduced the ability of facilities to meet emission reduction targets through allowance trading. Like CAIR, CSAPR set individual state caps for SO2 and NOx emissions. However, unlike CAIR in which states allocated allowances to generating units through state implementation plans, CSAPR allowances were allocated to individual units directly through the federal rule. CSAPR reductions were to be achieved with initial step reductions beginning January 1, 2012, and final compliance to be achieved in 2014. Multiple administrative and judicial challenges were filed. On December 30, 2011, the Court granted a stay of CSAPR and left CAIR in place pending its review. On August 21, 2012, the Court vacated CSAPR and directed the EPA to continue to administer CAIR. On October 5, the EPA filed its request for a hearing before the full federal appeals court that struck down the CSAPR. The original August decision vacating CSAPR was made by a three judge panel. EPA is currently seeking reconsideration of the issues raised on appeal before the full appellate panel. The Company remains in full compliance with CAIR (see additional information below "Conclusions Regarding Air Regulations").

Mercury and Air Toxics (MATS) Rule

On December 21, 2011, the EPA finalized the Utility MATS Rule. The MATS Rule is the EPA’s response to the US Court of Appeals for the District of Columbia vacating the Clean Air Mercury Rule (CAMR) in 2008. CAMR was originally established in 2005 as a nation-wide mercury emission allowance cap and trade system which sought to reduce utility emissions of mercury starting in 2010.

The MATS Rule sets emission limits for hazardous air pollutants for existing and new coal-fired power plants and identifies the following broad categories of hazardous air pollutants: mercury, non-mercury hazardous air pollutants (primarily arsenic, chromium, cobalt, and selenium) and acid gases (hydrogen cyanide, hydrogen chloride, and hydrogen fluoride). The rule

14

imposes mercury emission limits for two sub-categories of coal, and proposed surrogate limits for non-mercury and acid gas hazardous air pollutants. The EPA did not grant blanket compliance extensions, but asserted that states have broad authority to grant one year extensions for individual units where potential reliability impacts have been demonstrated. Reductions are to be achieved within three years of publication of the final rule in the Federal register (April 2015). Initiatives to suspend CSAPR’s implementation by the Congress also apply to the implementation of the MATS rule. Multiple judicial challenges were filed and briefing is proceeding. The EPA also recently announced it will reconsider MATS requirements for new construction. Such requirements are more stringent than those for existing plants. Utilities planning new coal-fired generation had argued standards outlined in the MATS could not be attained even using the best available control technology.

Conclusions Regarding Air Regulations

To comply with Indiana’s implementation plan of the Clean Air Act, and other federal air quality standards, the Company obtained authority from the IURC to invest in clean coal technology. Using this authorization, the Company invested approximately $411 million starting in 2001 with the last equipment being placed into service on January 1, 2010. The pollution control equipment included Selective Catalytic Reduction (SCR) systems, fabric filters, and an SO2 scrubber at its generating facility that is jointly owned with ALCOA (the Company’s portion is 150 MW). SCR technology is the most effective method of reducing NOx emissions where high removal efficiencies are required and fabric filters control particulate matter emissions. The unamortized portion of the $411 million clean coal technology investment was included in rate base for purposes of determining SIGECO’s new electric base rates approved in the latest base rate order obtained April 27, 2011. SIGECO’s coal fired generating fleet is 100 percent scrubbed for SO2 and 90 percent controlled for NOx.

Utilization of the Company’s NOx and SO2 allowances can be impacted as regulations are revised and implemented. Most of these allowances were granted to the Company at zero cost; therefore, any reduction in carrying value that could result from future changes in regulations would be immaterial.

The Company is currently reviewing the sufficiency of its existing pollution control equipment in relation to the requirements described in the MATS Rule and the 2015 requirement imposed by CAIR. Based upon an initial review, the Company believes that it will be able to meet these requirements with its existing suite of pollution control equipment. However, it is possible some minor modifications to the control equipment, additional operating expenses, and/or the purchase of some allowances could be required. The Company believes that such additional costs, if necessary, would be recoverable under Indiana Senate Bill 251 referenced above.

Notice of Violation Received

The Company received a notice of violation (NOV) from the EPA pertaining to its A.B. Brown power plant. The NOV asserts that when the power plant was equipped with SCRs the correct permits were not obtained or the best available control technology to control incidental sulfuric acid mist was not installed. Based on the Company’s understanding of the New Source Review reform in effect when the equipment was installed, it is the Company’s position that its SCR project was exempted from such requirements. At this time the Company is reviewing the potential impact this NOV could have on operating costs. To the extent costs to comply increase, they should be recoverable under Indiana law.

Water

Section 316(b) of the Clean Water Act requires that generating facilities use the “best technology available” to minimize adverse environmental impacts in a body of water. More specifically, Section 316(b) is concerned with impingement and entrainment of aquatic species in once-through cooling water intake structures used at electric generating facilities. In April 2009, the U.S. Supreme Court affirmed that the EPA could, but was not required to, consider costs and benefits in making the evaluation as to the best technology available for existing generating facilities. The regulation was remanded back to the EPA for further consideration. In March 2011, the EPA released its proposed Section 316(b) regulations. The EPA did not mandate the retrofitting of cooling towers in the proposed regulation, but if finalized the regulation will leave it to the state to determine whether cooling towers should be required on a case by case basis. A final rule is expected in 2013. Depending on the final rule and on the Company’s facts and circumstances, capital investments could be in the $40 million range if new infrastructure, such as new cooling water towers, is required. Costs for compliance with these final regulations would likely qualify as federally mandated regulatory requirements under Indiana Senate Bill 251 referenced above.

15

Coal Ash Waste Disposal & Ash Ponds

In June 2010, the EPA issued proposed regulations affecting the management and disposal of coal combustion products, such as ash generated by the Company’s coal-fired power plants. The proposed rules more stringently regulate these byproducts and would likely increase the cost of operating or expanding existing ash ponds and the development of new ash ponds. The alternatives include regulating coal combustion by-products that are not being beneficially reused as hazardous waste. The EPA did not offer a preferred alternative, but took public comment on multiple alternative regulations. Rules may not be finalized in 2012 given oversight hearings, congressional interest, and other factors.

At this time, the majority of the Company’s ash is being beneficially reused. However, the alternatives proposed would require modification to or closure of existing ash ponds. The Company estimates capital expenditures to comply could be as much as $30 million, and such expenditures could exceed $100 million if the most stringent of the alternatives is selected. Annual compliance costs could increase slightly or be impacted by as much as $5 million. Costs for compliance with these regulations would likely qualify as federally mandated regulatory requirements and be recovered under Senate Bill 251 referenced above.

Climate Change

In April 2007, the US Supreme Court determined that greenhouse gases meet the definition of "air pollutant" under the Clean Air Act and ordered the EPA to determine whether greenhouse gas emissions from motor vehicles cause or contribute to air pollution that may reasonably be anticipated to endanger public health or welfare. In April 2009, the EPA published its proposed endangerment finding for public comment. The proposed endangerment finding concludes that carbon emissions from mobile sources pose an endangerment to public health and the environment. The endangerment finding was finalized in December 2009, and is the first step toward EPA regulating carbon emissions through the existing Clean Air Act in the absence of specific carbon legislation from Congress. The EPA has promulgated two greenhouse gas regulations that apply to the Company’s generating facilities. In 2009, the EPA finalized a mandatory greenhouse gas emissions registry which requires the reporting of emissions. The EPA has also finalized a revision to the Prevention of Significant Deterioration (PSD) and Title V permitting rules which would require facilities that emit 75,000 tons or more of greenhouse gases a year to obtain a PSD permit for new construction or a significant modification of an existing facility. EPA's PSD and Title V permitting rules for GHG's were recently upheld by the US Court of Appeals for the District of Columbia. In April 2012, the EPA issued its proposed new source performance standards for greenhouse gases applicable to new construction. This proposed rule does not apply to existing sources, such as Vectren’s generating facilities. The EPA has not indicated when it intends to propose standards for existing sources.

Numerous competing federal legislative proposals have also been introduced in recent years that involve carbon, energy efficiency, and renewable energy. Comprehensive energy legislation at the federal level continues to be debated, but there has been little progress to date. The progression of regional initiatives throughout the United States has also slowed.

Impact of Legislative Actions & Other Initiatives is Unknown

If regulations are enacted by the EPA or other agencies or if legislation requiring reductions in CO2 and other greenhouse gases or legislation mandating a renewable energy portfolio standard is adopted, such regulation could substantially affect both the costs and operating characteristics of the Company’s fossil fuel generating plants, nonutility coal mining operations, and natural gas distribution businesses. At this time and in the absence of final legislation or rulemaking, compliance costs and other effects associated with reductions in greenhouse gas emissions or obtaining renewable energy sources remain uncertain. The Company has gathered preliminary estimates of the costs to control greenhouse gas emissions. A preliminary investigation demonstrated costs to comply would be significant, first with regard to operating expenses and later for capital expenditures as technology becomes available to control greenhouse gas emissions. However, these compliance cost estimates are based on highly uncertain assumptions, including allowance prices if a cap and trade approach were employed, and energy efficiency targets. Costs to purchase allowances that cap greenhouse gas emissions or expenditures made to control emissions should be considered a cost of providing electricity, and as such, the Company believes such costs and expenditures would be recoverable from customers through Senate Bill 251.

Manufactured Gas Plants

In the past, the Company operated facilities to manufacture natural gas. Given the availability of natural gas transported by pipelines, these facilities have not been operated for many years. Under current environmental laws and regulations, those that

16

owned or operated these facilities may now be required to take remedial action if certain contaminants are found above the regulatory thresholds at these sites.

In the Indiana Gas service territory, the existence, location, and certain general characteristics of 26 gas manufacturing and storage sites have been identified for which the Company may have some remedial responsibility. A remedial investigation/feasibility study (RI/FS) was completed at one of the sites under an agreed order between Indiana Gas and the IDEM, and a Record of Decision was issued by the IDEM in January 2000. The remaining sites have been submitted to the IDEM's Voluntary Remediation Program (VRP). The Company has identified its involvement in five manufactured gas plant sites in SIGECO’s service territory, all of which are currently enrolled in the IDEM’s VRP. The Company is currently conducting some level of remedial activities, including groundwater monitoring at certain sites.

The Company has accrued the estimated costs for further investigation, remediation, groundwater monitoring, and related costs for the sites. While the total costs that may be incurred in connection with addressing these sites cannot be determined at this time, the Company has recorded cumulative costs that it reasonably expects to incur totaling approximately $41.7 million ($23.2 million at Indiana Gas and $18.5 million at SIGECO). The estimated accrued costs are limited to the Company’s share of the remediation efforts and are therefore net of exposures of other potentially responsible parties (PRP).

With respect to insurance coverage, Indiana Gas has received approximately $20.8 million from all known insurance carriers under insurance policies in effect when these plants were in operation. SIGECO filed a declaratory judgment action against its insurance carriers seeking a judgment finding its carriers liable under the policies for coverage of further investigation and any necessary remediation costs that SIGECO may accrue under the VRP program and/or another site subject to a lawsuit that has been settled. In November 2011, the Court ruled on two motions for summary judgment, finding for SIGECO and against certain insurers on indemnification and defense obligations in the policies at issue. SIGECO has settlement agreements with all known insurance carriers and has recorded approximately $15.2 million of expected insurance recoveries.

The costs the Company expects to incur are estimated by management using assumptions based on actual costs incurred, the timing of expected future payments, and inflation factors, among others. While the Company’s utilities have recorded all costs which they presently expect to incur in connection with activities at these sites, it is possible that future events may require some level of additional remedial activities which are not presently foreseen and those costs may not be subject to PRP or insurance recovery. As of September 30, 2012 and December 31, 2011, respectively, approximately $4.8 million and $6.5 million of accrued, but not yet spent, costs are included in Other Liabilities related to both the Indiana Gas and SIGECO sites.

12.

Rate & Regulatory Matters

Vectren South Electric Base Rate Filing

On December 11, 2009, Vectren South filed a request with the IURC to adjust its base electric rates. The requested increase in base rates addressed capital investments, a modified electric rate design that would facilitate a partnership between Vectren South and customers to pursue energy efficiency and conservation, and new energy efficiency programs to complement those currently offered for natural gas customers. The IURC issued an order in the case on April 27, 2011. The order provides for an approximate $28.6 million revenue increase to recover costs associated with approximately $325 million in system upgrades that were completed in the three years leading up to the December 2009 filing and modest increases in maintenance and operating expenses. The approved revenue increase is based on rate base of $1,295.6 million, return on equity of 10.4 percent and an overall rate of return of 7.29 percent. The new rates were effective May 3, 2011. The IURC, in its order, denied the Company’s request for implementation of the decoupled rate design, which is discussed further below. Addressing issues raised in the case concerning coal supply contracts and related costs, the IURC found that current coal contracts remain effective and that a prospective review process of future procurement decisions would be initiated.

Coal Procurement Procedures

Vectren South submitted a request for proposal in April 2011 regarding coal purchases for a four year period beginning in 2012. After negotiations with bidders, Vectren South reached an agreement in principle for multi-year purchases with two suppliers, one of which is Vectren Fuels, Inc. Consistent with the IURC direction in the electric rate case, a sub docket proceeding was established to review the Company’s prospective coal procurement procedures, and the Company submitted evidence related to its recent request for proposal (RFP) and those coal procurement procedures to the IURC in September

17

2011. In March 2012, the IURC issued its order in the sub docket. The order concluded that Vectren South’s 2011 RFP process resulted in prices at the lowest fuel cost reasonably possible. The IURC will continue to regularly monitor Vectren South’s procurement process in future fuel adjustment proceedings.

Vectren South Electric Fuel Cost Reduction

In the spring of 2011, Vectren South secured contracts for lower coal costs through a formal bidding process. This lower-priced contract coal started being delivered to Vectren’s power plants during 2012. On December 5, 2011 within the quarterly FAC filing, Vectren South submitted a joint proposal with the OUCC to reduce its fuel costs by accelerating into 2012 the impact of lower cost coal under new term contracts effective after 2012. The cost difference will be deferred to a regulatory asset and recovered over a six-year period without interest beginning in 2014. The IURC approved this proposal on January 25, 2012, with a positive impact to customer’s rates effective February 1, 2012. The deferred amount includes a reduction in the value of the coal inventory at December 31, 2011 of approximately $17.7 million to reflect existing coal inventory at the new, lower price. Deferrals related to coal purchases in 2012 have totaled approximately $24.7 million, bringing the total deferred balance as of September 30, 2012 to the expected level of $42.4 million. In addition to coal purchased under these contracts, Vectren South has also recently contracted with Vectren Fuels, Inc. to purchase lower priced spot coal. This spot purchase was found to be reasonable in a recent FAC order.

Vectren South Electric Demand Side Management Program Filing

On August 16, 2010, Vectren South filed a petition with the IURC, seeking approval of its proposed electric Demand Side Management (DSM) Programs, recovery of the costs associated with these programs, recovery of lost margins as a result of implementing these programs for large customers, and recovery of performance incentives linked with specific measurement criteria on all programs. The DSM Programs proposed are consistent with a December 9, 2009 order issued by the IURC, which, among other actions, defined long-term conservation objectives and goals of DSM programs for all Indiana electric utilities under a consistent statewide approach. In order to meet these objectives, the IURC order divided the DSM programs into Core and Core Plus programs. Core programs are joint programs required to be offered by all Indiana electric utilities to all customers, and include some for large industrial customers. Core Plus programs are those programs not required specifically by the IURC, but defined by each utility to meet the overall energy savings targets defined by the IURC.

On August 31, 2011 the IURC issued an order approving an initial three year DSM plan in the Vectren South service territory that complies with the IURC’s energy saving targets. Consistent with the Company’s proposal, the order approved, among other items, the following: 1) recovery of costs associated with implementing the DSM Plan; 2) the recovery of a performance incentive mechanism based on measured savings related to certain DSM programs; 3) lost margin recovery associated with the implementation of DSM programs for large customers; and 4) deferral of lost margin up to $1 million in 2011 associated with small customer DSM programs for subsequent recovery under a tracking mechanism to be proposed by the Company. On June 20, 2012, the IURC issued an order approving a small customer lost margin recovery mechanism, inclusive of all previous deferrals. This mechanism is an alternative to the electric decoupling proposal that was denied by the IURC in the Company's last base rate proceeding discussed earlier.

Vectren South Electric Dense Pack Filing

On September 14, 2011, Vectren South filed a petition with the IURC seeking recovery of and return on the capital investment in dense pack technology to improve the efficiency of its A.B. Brown Generating Station. This investment is expected to be approximately $32 million over the next two years, of which approximately $25.5 million has been invested to date. This technology is expected to allow the A.B. Brown units to run at least 5 percent more efficient, thereby burning less fuel, and reducing fuel costs and emissions of pollutants. In the Company’s base rate order issued in April 2011, the IURC authorized deferred accounting treatment associated with this investment. As a result of a subsequent filing by the Company seeking a current recovery mechanism in lieu of the deferred accounting treatment, the IURC issued an order on July 11, 2012, denying the Company's request for a current recovery mechanism stating that dense pack technology does not qualify as advanced technology under the statute. Although the Company believes that the investment does meet the requirements of the statute that would have allowed for timely recovery, it does not plan to appeal the decision and will employ the deferred accounting treatment ordered in the Company's last base rate order discussed earlier.

18

Vectren North Reporting Location Consolidation Proceeding

Vectren North implemented a reporting location consolidation plan in 2011 and converted certain reporting locations into staging areas throughout the Vectren North territory. On May 26, 2011, the International Brotherhood of Electrical Workers Local 1393, United Steel Workers Locals 12213 and 7441 and others (the “Complainants”) filed a formal complaint with the IURC claiming that implementation of the consolidation plan by Vectren North endangers public safety and impairs Vectren North's ability to provide adequate, safe and reliable service. The Complainants asked the IURC to require Vectren North to reopen previously consolidated reporting locations and maintain and staff those locations. A hearing in this case was held in February 2012 and the Company is awaiting the issuance of an order.

13.

Impact of Recently Issued Accounting Principles

Other Comprehensive Income (OCI)

In 2011, the FASB issued new accounting guidance regarding the presentation of comprehensive income within financial statements. The new guidance will require entities to report components of comprehensive income in either (1) a continuous statement of comprehensive income or (2) two separate but consecutive statements. Under the two-statement approach, the first statement would include components of net income, which is consistent with the income statement format used today, and the second statement would include components of OCI. The guidance does not change the items that must be reported in OCI. The new guidance is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011 and retrospective application is required. The Company adopted this guidance, as amended for condensed quarterly reporting, for the quarterly reporting period ended March 31, 2012 by reporting comprehensive income as required.

Goodwill Testing

In September 2011, the FASB issued new accounting guidance regarding testing goodwill for impairment. The new guidance will allow the Company an option to first assess qualitative factors to determine whether it is necessary to perform the two-step quantitative goodwill impairment test. Using the new guidance, the Company no longer would be required to calculate the fair value of a reporting unit unless the Company determines, based on that qualitative assessment, that it is more likely than not that its fair value is less than its carrying amount. The Company considered this option during its quarterly reporting period ended March 31, 2012 and concluded the continuation of the use of a quantitative approach is appropriate.

Fair Value Measurement and Disclosure

In May 2011, the FASB issued accounting guidance to improve the comparability of fair value measurements presented and disclosed in financial statements prepared in accordance with U.S. GAAP and International Financial Reporting Standards (IFRS). The amendments are not intended to change the application of the current fair value requirements, but to clarify the application of existing requirements. The guidance does change particular principles or requirements for measuring fair value or disclosing information about fair value measurements. To improve consistency, language has been changed to ensure that U.S. GAAP and IFRS fair value measurement and disclosure requirements are described in the same way. The Company adopted this guidance for its quarterly reporting period ended March 31, 2012. The adoption of this guidance did not have a material impact on our financial position, results of operations or cash flows.

14.

Fair Value Measurements

The carrying values and estimated fair values using primarily Level 2 assumptions of the Company's other financial instruments follow:

September 30, 2012

December 31, 2011

(In millions)

Carrying

Amount

Est. Fair

Value

Carrying

Amount

Est. Fair

Value

Long-term debt

$

1,585.2

$

1,836.2

$

1,622.3

$

1,804.4

Short-term borrowings

316.2

316.2

227.1

227.1

Cash & cash equivalents

7.0

7.0

8.6

8.6

For the balance sheet dates presented in these financial statements, the Company had no material assets or liabilities recorded at fair value outstanding.

19

Certain methods and assumptions must be used to estimate the fair value of financial instruments. The fair value of the Company's long-term debt was estimated based on the quoted market prices for the same or similar issues or on the current rates offered to the Company for instruments with similar characteristics. Because of the maturity dates and variable interest rates of short-term borrowings and cash & cash equivalents, those carrying amounts approximate fair value. Because of the inherent difficulty of estimating interest rate and other market risks, the methods used to estimate fair value may not always be indicative of actual realizable value, and different methodologies could produce different fair value estimates at the reporting date.

Under current regulatory treatment, call premiums on reacquisition of long-term debt supporting utility operations are generally recovered in customer rates over the life of the refunding issue or over a 15-year period. Accordingly, any reacquisition would not be expected to have a material effect on the Company's results of operations.

Because of the customized nature of notes receivable investments and lack of a readily available market, it is not practical to estimate the fair value of these financial instruments at specific dates without considerable effort and cost. At September 30, 2012 and December 31, 2011, the fair value for these financial instruments was not estimated. The carrying value of notes receivable, inclusive of any accrued interest and net of impairment reserves, was approximately $2.1 million at September 30, 2012 and December 31, 2011, and is reflected in Other Nonutility Investments in the Consolidated Condensed Balance Sheets.

15.

Segment Reporting

The Company segregates its operations into three groups: 1) Utility Group, 2) Nonutility Group, and 3) Corporate and Other.

The Utility Group is comprised of Vectren Utility Holdings, Inc.’s operations, which consist of the Company’s regulated operations and other operations that provide information technology and other support services to those regulated operations. The Company segregates its regulated operations between Gas Utility Services and Electric Utility Services. Gas Utility Services provides natural gas distribution and transportation services to nearly two-thirds of Indiana and to west-central Ohio. Electric Utility Services provides electric distribution services to southwestern Indiana, and includes the Company’s power generating and wholesale power operations. Regulated operations supply natural gas and/or electricity to over one million customers. In total, the Utility Group reports three segments: Gas Utility Services, Electric Utility Services, and Other operations.

The Nonutility Group reports five segments: Infrastructure Services, Energy Services, Coal Mining, Energy Marketing, and Other Businesses. Segment information below reflects the March 31, 2011 acquisition of Minnesota Limited, Inc. in the Infrastructure Services segment and the December 31, 2011 sale of Vectren Source in Energy Marketing segment.

Corporate and Other includes unallocated corporate expenses such as advertising and charitable contributions, among other activities, that benefit the Company’s other operations. Net income is the measure of profitability used by management for all operations. Information related to the Company’s reportable segments is summarized as follows:

20

Three Months Ended

Nine Months Ended

September 30,

September 30,

(In millions)

2012

2011

2012

2011

Revenues

Utility Group

Gas Utility Services

$

100.2

$

102.1

$

508.5

$

592.8

Electric Utility Services

167.9

186.7

456.6

492.4

Other Operations

10.2

11.0

30.1

32.9

Eliminations

(10.6

)

(10.5

)

(29.6

)

(31.4

)

Total Utility Group

267.7

289.3

965.6

1,086.7

Nonutility Group

Infrastructure Services

182.2

151.6

449.2

293.4

Energy Services

34.2

48.5

85.6

111.5

Coal Mining

53.4

81.0

171.7

221.2

Energy Marketing

—

10.5

—

105.4

Other Businesses

0.1

—

0.4

—

Total Nonutility Group

269.9

291.6

706.9

731.5

Eliminations

(24.1

)

(41.5

)

(83.8

)

(120.4

)

Consolidated Revenues

$

513.5

$

539.4

$

1,588.7

$

1,697.8

Profitability Measure - Net Income (Loss)

Utility Group

Gas Utility Services

$

(2.7

)

$

(4.8

)

$

36.1

$

33.5

Electric Utility Services

26.6

30.8

59.4

53.1

Other Operations

2.5

1.9

7.0

6.2

Utility Group Net Income

26.4

27.9

102.5

92.8

Nonutility Group Net Income (Loss)

Infrastructure Services

15.9

11.9

27.3

11.1

Energy Services

2.6

2.3

0.9

1.6

Coal Mining

(2.2

)

5.8

—

15.9

Energy Marketing

(2.4

)

(12.2

)

(13.5

)

(24.3

)

Other Businesses

(0.7

)

(0.2

)

(0.6

)

(0.9

)

Nonutility Group Net Income (Loss)

13.2

7.6

14.1

3.4

Corporate & Other Group Net Income (Loss)

(0.3

)

(0.2

)

(0.4

)

(1.2

)

Consolidated Net Income

$

39.3

$

35.3

$

116.2

$

95.0

21

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Vectren Corporation (the Company or Vectren), an Indiana corporation, is an energy holding company headquartered in Evansville, Indiana. The Company’s wholly owned subsidiary, Vectren Utility Holdings, Inc. (Utility Holdings), serves as the intermediate holding company for three public utilities: Indiana Gas Company, Inc. (Indiana Gas or Vectren North), Southern Indiana Gas and Electric Company (SIGECO or Vectren South), and Vectren Energy Delivery of Ohio, Inc. (VEDO). Utility Holdings also earns a return on shared assets that provide information technology and other services to the three utilities. Utility Holdings’ consolidated operations are collectively referred to as the Utility Group. Both Vectren and Utility Holdings are holding companies as defined by the Energy Policy Act of 2005 (Energy Act). Vectren was incorporated under the laws of Indiana on June 10, 1999.

Indiana Gas provides energy delivery services to approximately 564,000 natural gas customers located in central and southern Indiana. SIGECO provides energy delivery services to approximately 142,000 electric customers and approximately 110,000 gas customers located near Evansville in southwestern Indiana. SIGECO also owns and operates electric generation assets to serve its electric customers and optimizes those assets in the wholesale power market. Indiana Gas and SIGECO generally do business as Vectren Energy Delivery of Indiana. VEDO provides energy delivery services to approximately 310,000 natural gas customers located near Dayton in west-central Ohio.

The Company, through Vectren Enterprises, Inc. (Enterprises), is involved in nonutility activities in four primary business areas: Infrastructure Services, Energy Services, Coal Mining, and Energy Marketing. Infrastructure Services provides underground construction and repair services. Energy Services provides performance contracting and renewable energy services. Coal Mining mines and sells coal. Energy Marketing markets and supplies natural gas and provides energy management services. Enterprises also has other legacy businesses that have invested in energy-related opportunities and services, real estate, and leveraged leases, among other investments. All of the above are collectively referred to as the Nonutility Group. Enterprises supports the Company’s regulated utilities pursuant to service contracts by providing natural gas supply services, coal, and infrastructure services.

Executive Summary of Consolidated Results of Operations

In this discussion and analysis, the Company analyzes contributions to consolidated earnings and earnings per share from its Utility Group and Nonutility Group separately since each operates independently requiring distinct competencies and business strategies, offers different energy and energy related products and services, and experiences different opportunities and risks.

The Utility Group generates revenue primarily from the delivery of natural gas and electric service to its customers. The primary source of cash flow for the Utility Group results from the collection of customer bills and the payment for goods and services procured for the delivery of gas and electric services. The activities of, and revenues and cash flows generated by, the Nonutility Group are closely linked to the utility industry, and the results of those operations are generally impacted by factors similar to those impacting the overall utility industry. In addition, there are other operations, referred to herein as Corporate and Other, that include unallocated corporate expenses such as advertising and charitable contributions, among other activities.

The Company has in place a disclosure committee that consists of senior management as well as financial management. The committee is actively involved in the preparation and review of the Company’s SEC filings. The following discussion and analysis should be read in conjunction with the unaudited condensed consolidated financial statements and notes thereto as well as the Company’s 2011 annual report filed on Form 10-K.

22

Net income and earnings per share, in total and by group, for the three and nine months endedSeptember 30, 2012 and 2011 follow:

Three Months Ended

Nine Months Ended

September 30,

September 30,

(In millions, except per share data)

2012

2011

2012

2011

Net income (loss)

$

39.3

$

35.3

$

116.2

$

95.0

Attributed to:

Utility Group

26.4

27.9

102.5

92.8

Nonutility Group

13.2

7.6

14.1

3.4

Corporate & other

(0.3

)

(0.2

)

(0.4

)

(1.2

)

Basic EPS

$

0.48

$

0.43

$

1.42

$

1.16

Attributed to:

Utility Group

0.32

0.34

1.25

1.13

Nonutility Group

0.16

0.09

0.17

0.04

Corporate & other

—

—

—

(0.01

)

Utility Group

In the third quarter of 2012, the Utility Group earnings were $26.4 million, compared to $27.9 million in 2011. In the nine months ended September 30, 2012, the Utility Group earned $102.5 million, compared to the $92.8 million in 2011. Increased year-over-year results for the nine month periods reflect, among other things, the impacts of new electric base rates implemented on May 3, 2011 and lower interest expense as a result of refinancing activity in the last quarter of 2011 and first quarter of 2012. The decrease in the quarter-over-quarter results generally reflects lower earnings from electric utility operations associated with higher operating expenses and lower small customer margins.

Gas Utility Services

During the third quarter of 2012, Gas Utility Services operated at a seasonal loss of $2.7 million, compared to a loss of $4.8 million in the third quarter of 2011. In the nine months ended September 30, 2012, gas utility operations earned $36.1 million, compared to earnings of $33.5 million in 2011. Both the quarter and year to date period reflect increased earnings from investment in bare steel cast iron replacement activities and favorable interest expense due to the recent refinancing activity.

Electric Utility Services

During the third quarter of 2012, Electric Utility earnings were $26.6 million, compared to $30.8 million in the third quarter of 2011. Electric operations earned $59.4 million year to date in 2012, compared to earnings of $53.1 million for the nine months endedSeptember 30, 2011. Improved year to date results in 2012 reflect increased electric margin, primarily from base rate changes and lower interest costs. The decrease in the quarter-over-quarter results generally reflects higher operating expenses and lower customer margins from conservation beyond approved lost margin recovery mechanisms, which more than offset slightly warmer weather in the quarter as compared to the same quarter in 2011.

Other Utility Operations

In the third quarter of 2012, earnings from Other Utility operations were $2.5 million, compared to $1.9 million in 2011. In the nine months ended September 30, 2012, earnings from these operations were $7.0 million, compared to $6.2 million in 2011. The 2011 year to date results include a $1.4 million unfavorable tax adjustment. In addition, variability in the earnings of the segment occurs as the allocation of shared asset costs changes.

Nonutility Group

During the 2012 third quarter, earnings from Nonutility operations were $13.2 million, compared to earnings of $7.6 million in 2011. Year to date in 2012, the Nonutility Group earned $14.1 million, which compares to earnings of $3.4 million in 2011. Infrastructure Services results increased $4.0 million quarter over quarter and $16.2 million year to date compared to the prior year periods. These increases are reflective of increased demand for services. In the third quarter and the 2012 year to date period, Vectren's share of ProLiance's losses have been reduced by $6.2 million and $11.8 million, respectively. However, Coal Mining results are lower in the quarter by $8.0 million and $15.9 million year to date primarily due to the softness in the overall coal market.

23

Retail energy marketer Vectren Source, which was sold on December 31, 2011, operated at a seasonal loss of $3.6 million during the third quarter of 2011. Year to date in 2011, earnings from Vectren Source were $1.0 million and $2.8 million for the full year.

Dividends

Dividends declared for the three months ended September 30, 2012, were $0.350 per share, compared to $0.345 per share for the same period in 2011. Dividends declared for the nine months ended September 30, 2012, were $1.050 per share, compared to $1.035 per share for the same period in 2011. In November 2012, the Company's board of directors increased the quarterly dividend to $0.355 per share from $0.350 per share. The increase marks the 53rd consecutive year in which Vectren and predecessor companies have increased annual dividends paid.

Use of Non-GAAP Performance Measures and Per Share Measures

Per share earnings contributions of the Utility Group, Nonutility Group, and Corporate and Other are presented and are non-GAAP measures. Such per share amounts are based on the earnings contribution of each group included in Vectren’s consolidated results divided by Vectren’s basic average shares outstanding during the period. The earnings per share of the groups do not represent a direct legal interest in the assets and liabilities allocated to the groups, but rather represent a direct equity interest in Vectren Corporation's assets and liabilities as a whole. These non-GAAP measures are used by management to evaluate the performance of individual businesses. In addition, other items giving rise to period over period variances, such as weather, may be presented on an after tax and per share basis. These amounts are calculated at a statutory tax rate divided by Vectren’s basic average shares outstanding during the period. Accordingly, management believes these measures are useful to investors in understanding each business’ contribution to consolidated earnings per share and in analyzing consolidated period to period changes and the potential for earnings per share contributions in future periods. Reconciliations of the non-GAAP measures to their most closely related GAAP measure of consolidated earnings per share are included throughout this discussion and analysis. The non-GAAP financial measures disclosed by the Company should not be considered a substitute for, or superior to, financial measures calculated in accordance with GAAP, and the financial results calculated in accordance with GAAP.

Detailed Discussion of Results of Operations

Following is a more detailed discussion of the results of operations of the Company’s Utility and Nonutility operations. The detailed results of operations for these groups are presented and analyzed before the reclassification and elimination of certain intersegment transactions necessary to consolidate those results into the Company’s Consolidated Condensed Statements of Income.

Results of Operations of the Utility Group

The Utility Group is comprised of Utility Holdings’ operations and consists of the Company’s regulated operations and other operations that provide information technology and other support services to those regulated operations. Regulated operations consist of a natural gas distribution business that provides natural gas distribution and transportation services to nearly two-thirds of Indiana and to west-central Ohio and an electric transmission and distribution business, which provides electric distribution services to southwestern Indiana, and the Company’s power generating and wholesale power operations. In total, these regulated operations supply natural gas and/or electricity to over one million customers.Utility Group operating results before certain intersegment eliminations and reclassifications for the three and nine months ended September 30, 2012 and 2011, follow:

24

Three Months Ended

Nine Months Ended

September 30,

September 30,

(In millions, except per share data)

2012

2011

2012

2011

OPERATING REVENUES

Gas utility

$

100.2

$

102.1

$

508.5

$

592.8

Electric utility

167.9

186.7

456.6

492.4

Other

(0.4

)

0.5

0.5

1.5

Total operating revenues

267.7

289.3

965.6

1,086.7

OPERATING EXPENSES

Cost of gas sold

28.1

30.5

197.0

274.4

Cost of fuel & purchased power

52.9

67.1

144.6

186.9

Other operating

71.8

66.7

229.5

231.8

Depreciation & amortization

46.3

47.8

142.7

143.9

Taxes other than income taxes

11.5

11.6

39.0

40.7

Total operating expenses

210.6

223.7

752.8

877.7

OPERATING INCOME

57.1

65.6

212.8

209.0

OTHER INCOME - NET

2.3

0.1

5.2

4.0

INTEREST EXPENSE

17.8

20.4

53.5

61.2

INCOME BEFORE INCOME TAXES

41.6

45.3

164.5

151.8

INCOME TAXES

15.2

17.4

62.0

59.0

NET INCOME

$

26.4

$

27.9

$

102.5

$

92.8

CONTRIBUTION TO VECTREN BASIC EPS

$

0.32

$

0.34

$

1.25

$

1.13

Utility Group Margin

Throughout this discussion, the terms Gas Utility margin and Electric Utility margin are used. Gas Utility margin is calculated as Gas utility revenues less the Cost of gas sold. Electric Utility margin is calculated as Electric utility revenues less Cost of fuel & purchased power. The Company believes Gas Utility and Electric Utility margins are better indicators of relative contribution than revenues since gas prices and fuel and purchased power costs can be volatile and are generally collected on a dollar-for-dollar basis from customers. Following is a discussion and analysis of margin generated from regulated utility operations.

Gas Utility Margin (Gas utility revenues less Cost of gas sold)

Gas Utility margin and throughput by customer type follows:

Three Months Ended

Nine Months Ended

September 30,

September 30,

(In millions)

2012

2011

2012

2011

Gas utility revenues

$

100.2

$

102.1

$

508.5

$

592.8

Cost of gas sold

28.1

30.5

197.0

274.4

Total gas utility margin

$

72.1

$

71.6

$

311.5

$

318.4

Margin attributed to:

Residential & commercial customers

$

58.5

$

58.4

$

263.1

$

268.4

Industrial customers

11.9

11.5

40.8

41.0

Other

1.7

1.7

7.6

9.0

Total gas utility margin

$

72.1

$

71.6

$

311.5

$

318.4

Sold & transported volumes in MMDth attributed to:

Residential & commercial customers

6.3

6.5

57.3

71.0

Industrial customers

25.1

20.7

77.2

70.6

Total sold & transported volumes

31.4

27.2

134.5

141.6

25

Gas Utility margins were $72.1 million and $311.5 million for the for the three and nine months ended September 30, 2012, and compared to 2011 increased $0.5 million quarter over quarter and decreased $6.9 million year to date. The impact of low natural gas prices and mild weather on revenue taxes, late and reconnect fees, and volumetric pass through costs decreased gas utility margin $1.0 million quarter over quarter and $8.4 million year to date. Returns generated on investments in bare steel/ cast iron and distribution riser replacement in Ohio increased margins $0.6 million in the quarter and $2.0 million year to date in 2012 compared to the prior year. With rate designs that substantially limit the impact of weather on margin, temperatures that were 71 percent of normal in Indiana and 83 percent of normal in Ohio during the peak winter heating season in early 2012 had a significant impact on volumes sold, but only a slightly negative impact on margin, reducing margin $0.7 million year over year. Excluding the impact of passthrough costs, large customer margins increased $0.7 million in the quarter, and due to the warm winter weather, have increased $0.4 million year over year.

Electric retail utility margins were $106.3 million and $286.5 million for the three and nine months ended September 30, 2012, and compared to 2011 decreased by $5.7 million in the quarter and increased $5.1 million year to date. The year to date increase is driven primarily by $10.0 million of incremental margin across all customer classes from new base rates effective May 3, 2011. Year to date, electric margin also benefited from higher volumes sold to industrial customers. However, margin was lower in the quarter and year to date on refunds resulting from statutory net operating income limits and lower third quarter small customer margins. The small customer margins were lower as a result of conservation beyond approved lost margin recovery mechanisms, which more than offset slightly warmer weather in the quarter as compared to the same quarter in 2011.

Electric results, which are not protected by weather mechanisms, were positively impacted in the third quarter of 2012 as a result of warm weather. In the third quarter of 2012, cooling temperatures were 119 percent of normal; this compares to the third quarter of 2011 when cooling temperatures were 114 percent of normal. In the third quarter of 2012, the increase in electric margin, net of amounts refunded to customers as discussed below, compared to normal temperatures was estimated to be $2.4 million. On a year to date basis, cooling temperatures that were 131 percent of normal offset the impact of mild first quarter heating weather. Management estimates the weather impact on electric margin year to date, net of refunds to customers, to be $1.0 million favorable.

Indiana regulation includes a statutory mechanism that can limit a utility's rolling twelve month net operating income to that authorized in its last general rate order, as adjusted for previous net operating income levels that were below authorized levels.

26

Should weather or other factors continue to increase net operating income in future periods, the full benefit of those favorable impacts on the company's electric utility may continue to be limited by the statutory earnings test.

Margin from Wholesale Electric Activities

Periodically, generation capacity is in excess of native load. The Company markets and sells this unutilized generating and transmission capacity to optimize the return on its owned assets. Substantially all off-system sales occur into the MISO Day Ahead and Real Time markets.

Further detail of Wholesale activity follows:

Three Months Ended

Nine Months Ended

September 30,

September 30,

(In millions)

2012

2011

2012

2011

Off-system sales

$

1.0

$

0.7

$

4.7

$

5.1

Transmission system sales

7.7

6.9

20.8

19.0

Total wholesale margin

$

8.7

$

7.6

$

25.5

$

24.1

The Company earns a return on electric transmission projects constructed by the Company in its service territory that meet the criteria of MISO’s regional transmission expansion plans. Margin associated with these projects, including the reconciliation of recovery mechanisms, and other transmission system operations, totaled $7.7 million during the three months September 30, 2012, compared to $6.9 million for the same period in 2011. Year to date in 2012 margins were $20.8 million compared to $19.0 million in the prior year. The increases in transmission system revenue is principally due to the increased investment in qualifying projects.

One such project currently under construction meeting these expansion plan criteria is an interstate 345 Kv transmission line that will connect Vectren’s A.B. Brown Generating Station to a station in Indiana owned by Duke Energy to the north and to a station in Kentucky owned by Big Rivers Electric Corporation to the south. During the construction of these transmission assets and while these assets are in service, SIGECO will recover an approximate 10 percent return, inclusive of the FERC approved equity rate of return of 12.38 percent, on capital investments through a rider mechanism which is projected annually and reconciled the following year based on actual results. Of the total investment, which is expected to approximate $110 million, the Company has invested approximately $98.5 million as of September 30, 2012. The north leg of this expansion was placed in service in November 2010, and the south leg of this project is expected to be operational later in 2012.

In the third quarter of 2012 margin from off system sales was $1.0 million compared to $0.7 million in 2011. For the nine months ended September 30, 2012, margin from off-system sales was $4.7 million, compared to $5.1 million for the nine months ended September 30, 2011. The base rate changes implemented in May 2011 require that wholesale margin from off-system sales earned above or below $7.5 million be shared equally with customers. This compares to a $10.5 million sharing threshold established in 2007. The year to date period reflects lower volumes sold, offset by the impacts of sharing which increased margin $0.6 million. Off-system sales totaled 184.4 GWh and 469.4 GWh during the nine months ended September 30, 2012 and 2011, respectively, reflecting reduced opportunities in 2012 due to unfavorable weather conditions when excess generation is more prevalent and the low cost of natural gas.

Utility Group Operating Expenses

Other Operating

For the three months ended September 30, 2012 operating expenses increased $5.1 million driven primarily by the timing of electric utility operating costs associated with planned outages and increased pipeline integrity management work in the Ohio natural gas service territory. For the nine months ended September 30, 2012, other operating expenses were $229.5 million, a decrease of $2.3 million, compared to 2011. The decrease is primarily driven by lower pass through costs and uncollectible accounts expenses associated with gas utility operations. The lower expenses are driven by lower, mostly weather-related, volumes sold and lower gas costs. Continuous improvement initiatives throughout the Utility Group are being implemented to limit growth in operating expenses over the coming years. The Company estimates that year to date in 2012 these initiatives have resulted in sustainable savings of over $4 million. Examples of the initiatives implemented thus far in 2012 include

27

improved processes that have allowed the company to become more efficient in completing work and thereby reduce labor costs, and recent amendments to postretirement medical plans that provide better access to benefits for company retirees at lower costs. These sustainable savings have aided in offsetting planned increases in energy delivery related operating expenses. Operating costs overall in 2012 are expected to be about flat to 2011 on an annual basis.

Depreciation & Amortization

For the three and nine months ended September 30, 2012, depreciation and amortization expense was $46.3 million and $142.7 million, respectively. Depreciation expense decreased $1.5 million in the quarter and $1.2 million year to date. Both the year to date and quarter reflect reductions associated with regulatory orders, offset by increased plant placed in service in gas and electric operations.

Taxes Other Than Income Taxes

In the 2012 third quarter taxes other than income taxes were $11.5 million and year to date in 2012 were $39.0 million. The year to date decrease of $1.7 million compared to the prior year was primarily due to lower usage taxes associated with lower gas and fuel costs. These expenses are offset dollar-for-dollar with lower gas utility and electric utility revenues.

Other Income-Net

Other income-net reflects income of $2.3 million for the third quarter and $5.2 million year to date in 2012. Increases of $2.2 million in the quarter and $1.2 million year to date compared to 2011 primarily reflect earnings on assets that fund benefit plans.

Interest Expense

Interest expense was $17.8 million and $53.5 million, respectively for the three and nine months ended September 30, 2012. Interest expense decreased $2.6 million in the quarter and $7.7 million year to date compared to 2011. The lower expense both in the quarter and year to date reflects fourth quarter of 2011 refinancing activity in which $250 million of long-term debt with a 6.625 percent interest rate matured and was replaced with $150 million of new long-term debt with an average interest rate of 5.12 percent and $100 million of short-term borrowings. During the fourth quarter of 2011, the Company also called $96.2 million of long-term debt at a rate of 5.95 percent and replaced that issuance in February 2012 with new debt at a rate of 5.0 percent.

Income Taxes

In the nine months ended September 30, 2012, federal and state income taxes were $62.0 million, an increase of $3.0 million compared to the prior year. In the quarter federal and state taxes decreased $2.2 million. The quarterly and year to date changes are primarily due to variances in pre-tax income. The year to date period in 2011 also included a one-time, unfavorable tax adjustment of $1.4 million.

Legislative Matters

Pipeline Safety Law

On January 3, 2012 the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 was signed into law. This new law, which reauthorizes federal pipeline safety programs through fiscal year 2015, provides for enhanced safety, reliability and environmental protection in the transportation of energy products by pipeline. The new law increases federal enforcement authority, grants the federal government expanded authority over pipeline safety, provides for new safety regulations and standards, and authorizes or requires the completion of several pipeline safety-related studies. The DOT is required to promulgate a number of new regulatory requirements. Those regulations may eventually lead to further regulatory or statutory requirements.

The Company continues to study the impact of the new law and potential new regulations associated with its implementation. At this time, compliance costs and other effects associated with the increased pipeline safety regulations remain uncertain. However, the new law is expected to result in further investment in pipeline inspections, and where necessary, additional modernization of pipeline infrastructure; and therefore, result in both increased levels of operating expenses and capital expenditures associated with the Company’s natural gas distribution businesses. Operating expenses associated with expanded compliance requirements may grow to approximately $9 million annually, with $6 million attributable to the Indiana operations. Related to the Indiana operations, the Company expects to seek recovery under Senate Bill 251 referenced below,

28

or such costs may be recoverable through current tracking mechanisms. Capital investments, driven by the pipeline safety regulations, associated with the Company’s gas utilities are expected to be significant. The Company expects to seek recovery of capital investments associated with complying with these federal mandates in accordance with Senate Bill 251 in Indiana and House Bill 95 or other currently authorized recovery mechanisms in Ohio (referenced below).

Indiana Senate Bill 251

In April 2011, Senate Bill 251 was signed into law. While the bill is broad in scope, it allows for cost recovery outside of a base rate proceeding for federal government mandated projects and provides for a voluntary clean energy portfolio standard.

The law applies to both gas and electric utility operations and provides a framework to recover 80 percent of federally mandated operating costs and capital investments through a periodic rate adjustment mechanism outside of a general rate case. Such costs include depreciation, operating and other costs. Construction costs receive a return on investment. The remaining 20 percent of those costs and capital investments are to be deferred for recovery in the utility’s next general rate case. The Company is currently evaluating the impact this law may have on its operations, including applicability to expenditures associated with the integrity, safety, and reliable operation of natural gas pipelines and facilities; ash disposal; water regulations; and air pollution control, including greenhouse gas emissions, among other federally mandated projects and potential projects.

Ohio House Bill 95

In June 2011, Ohio House Bill 95 was signed into law. The law adjusts, among other things, the manner in which gas utilities file for rate changes, including the implementation of base rate changes, alternative rate plans, and automatic rate adjustment mechanisms. Outside of a base rate proceeding, the legislation permits a natural gas company to apply for recovery of a capital expenditure program for infrastructure expansion, upgrade, or replacement; installation, upgrade, or replacement of information technology systems; or any program necessary to comply with government regulation. Once such application is approved, the legislation authorizes deferral of program costs, such as depreciation, property taxes, and debt-related carrying costs. On February 3, 2012, the Company initiated a filing under House Bill 95. This filing requests accounting authority to defer depreciation, debt-related post in service carrying costs and property taxes for its fifteen month capital expenditure program ending on December 31, 2012. The capital expenditure program totals $23.5 million and includes infrastructure expansion and improvements not covered by the Company’s distribution replacement rider as well as expenditures necessary to comply with PUCO rules, regulations and orders. The Company’s approach is consistent with approaches made by other Ohio utilities. A procedural schedule associated with the filing has been set and all respective responses have been submitted. It is anticipated the PUCO will act on the Company’s filing later this year.

Environmental Matters

Air Quality

Clean Air Interstate Rule / Cross-State Air Pollution Rule

In July 2011, the EPA finalized the Cross-State Air Pollution Rule (CSAPR). CSAPR was the EPA’s response to the US Court of Appeals for the District of Columbia’s (the Court) remand of the Clean Air Interstate Rule (CAIR). CAIR was originally established in 2005 as an allowance cap and trade program that required reductions from coal-burning power plants for NOx emissions beginning January 1, 2009 and SO2 emissions beginning January 1, 2010, with a second phase of reductions in 2015. In an effort to address the Court’s finding that CAIR did not adequately ensure attainment of pollutants in certain downwind states due to unlimited trading of SO2 and NOx allowances, CSAPR reduced the ability of facilities to meet emission reduction targets through allowance trading. Like CAIR, CSAPR set individual state caps for SO2 and NOx emissions. However, unlike CAIR in which states allocated allowances to generating units through state implementation plans, CSAPR allowances were allocated to individual units directly through the federal rule. CSAPR reductions were to be achieved with initial step reductions beginning January 1, 2012, and final compliance to be achieved in 2014. Multiple administrative and judicial challenges were filed. On December 30, 2011, the Court granted a stay of CSAPR and left CAIR in place pending its review. On August 21, 2012, the Court vacated CSAPR and directed the EPA to continue to administer CAIR. On October 5, the EPA filed its request for a hearing before the full federal appeals court that struck down the CSAPR. The original August decision vacating CSAPR was made by a three judge panel. EPA is currently seeking reconsideration of the issues raised on appeal before the full appellate panel. The Company remains in full compliance with CAIR (see additional information below "Conclusions Regarding Air Regulations").

29

Mercury and Air Toxics (MATS) Rule

On December 21, 2011, the EPA finalized the Utility MATS Rule. The MATS Rule is the EPA’s response to the US Court of Appeals for the District of Columbia vacating the Clean Air Mercury Rule (CAMR) in 2008. CAMR was originally established in 2005 as a nation-wide mercury emission allowance cap and trade system which sought to reduce utility emissions of mercury starting in 2010.

The MATS Rule sets emission limits for hazardous air pollutants for existing and new coal-fired power plants and identifies the following broad categories of hazardous air pollutants: mercury, non-mercury hazardous air pollutants (primarily arsenic, chromium, cobalt, and selenium) and acid gases (hydrogen cyanide, hydrogen chloride, and hydrogen fluoride). The rule imposes mercury emission limits for two sub-categories of coal, and proposed surrogate limits for non-mercury and acid gas hazardous air pollutants. The EPA did not grant blanket compliance extensions, but asserted that states have broad authority to grant one year extensions for individual units where potential reliability impacts have been demonstrated. Reductions are to be achieved within three years of publication of the final rule in the Federal register (April 2015). Initiatives to suspend CSAPR’s implementation by the Congress also apply to the implementation of the MATS rule. Multiple judicial challenges were filed and briefing is proceeding. The EPA also recently announced it will reconsider MATS requirements for new construction. Such requirements are more stringent than those for existing plants. Utilities planning new coal-fired generation had argued standards outlined in the MATS could not be attained even using the best available control technology.

Conclusions Regarding Air Regulations

To comply with Indiana’s implementation plan of the Clean Air Act, and other federal air quality standards, the Company obtained authority from the IURC to invest in clean coal technology. Using this authorization, the Company invested approximately $411 million starting in 2001 with the last equipment being placed into service on January 1, 2010. The pollution control equipment included Selective Catalytic Reduction (SCR) systems, fabric filters, and an SO2 scrubber at its generating facility that is jointly owned with ALCOA (the Company’s portion is 150 MW). SCR technology is the most effective method of reducing NOx emissions where high removal efficiencies are required and fabric filters control particulate matter emissions. The unamortized portion of the $411 million clean coal technology investment was included in rate base for purposes of determining SIGECO’s new electric base rates approved in the latest base rate order obtained April 27, 2011. SIGECO’s coal fired generating fleet is 100 percent scrubbed for SO2 and 90 percent controlled for NOx.

Utilization of the Company’s NOx and SO2 allowances can be impacted as regulations are revised and implemented. Most of these allowances were granted to the Company at zero cost; therefore, any reduction in carrying value that could result from future changes in regulations would be immaterial.

The Company is currently reviewing the sufficiency of its existing pollution control equipment in relation to the requirements described in the MATS Rule and the 2015 requirement imposed by CAIR. Based upon an initial review, the Company believes that it will be able to meet these requirements with its existing suite of pollution control equipment. However, it is possible some minor modifications to the control equipment, additional operating expenses, and/or the purchase of some allowances could be required. The Company believes that such additional costs, if necessary, would be recoverable under Indiana Senate Bill 251 referenced above.

Notice of Violation Received

The Company received a notice of violation (NOV) from the EPA pertaining to its A.B. Brown power plant. The NOV asserts that when the power plant was equipped with SCRs the correct permits were not obtained or the best available control technology to control incidental sulfuric acid mist was not installed. Based on the Company’s understanding of the New Source Review reform in effect when the equipment was installed, it is the Company’s position that its SCR project was exempted from such requirements. At this time the Company is reviewing the potential impact this NOV could have on operating costs. To the extent costs to comply increase, they should be recoverable under Indiana law.

Water

Section 316(b) of the Clean Water Act requires that generating facilities use the “best technology available” to minimize adverse environmental impacts in a body of water. More specifically, Section 316(b) is concerned with impingement and entrainment of aquatic species in once-through cooling water intake structures used at electric generating facilities. In April 2009, the U.S. Supreme Court affirmed that the EPA could, but was not required to, consider costs and benefits in making the evaluation as to

30

the best technology available for existing generating facilities. The regulation was remanded back to the EPA for further consideration. In March 2011, the EPA released its proposed Section 316(b) regulations. The EPA did not mandate the retrofitting of cooling towers in the proposed regulation, but if finalized the regulation will leave it to the state to determine whether cooling towers should be required on a case by case basis. A final rule is expected in 2013. Depending on the final rule and on the Company’s facts and circumstances, capital investments could be in the $40 million range if new infrastructure, such as new cooling water towers, is required. Costs for compliance with these final regulations would likely qualify as federally mandated regulatory requirements under Indiana Senate Bill 251 referenced above.

Coal Ash Waste Disposal & Ash Ponds

In June 2010, the EPA issued proposed regulations affecting the management and disposal of coal combustion products, such as ash generated by the Company’s coal-fired power plants. The proposed rules more stringently regulate these byproducts and would likely increase the cost of operating or expanding existing ash ponds and the development of new ash ponds. The alternatives include regulating coal combustion by-products that are not being beneficially reused as hazardous waste. The EPA did not offer a preferred alternative, but took public comment on multiple alternative regulations. Rules may not be finalized in 2012 given oversight hearings, congressional interest, and other factors.

At this time, the majority of the Company’s ash is being beneficially reused. However, the alternatives proposed would require modification to or closure of existing ash ponds. The Company estimates capital expenditures to comply could be as much as $30 million, and such expenditures could exceed $100 million if the most stringent of the alternatives is selected. Annual compliance costs could increase slightly or be impacted by as much as $5 million. Costs for compliance with these regulations would likely qualify as federally mandated regulatory requirements and be recovered under Senate Bill 251 referenced above.

Climate Change

In April 2007, the US Supreme Court determined that greenhouse gases meet the definition of "air pollutant" under the Clean Air Act and ordered the EPA to determine whether greenhouse gas emissions from motor vehicles cause or contribute to air pollution that may reasonably be anticipated to endanger public health or welfare. In April 2009, the EPA published its proposed endangerment finding for public comment. The proposed endangerment finding concludes that carbon emissions from mobile sources pose an endangerment to public health and the environment. The endangerment finding was finalized in December 2009, and is the first step toward EPA regulating carbon emissions through the existing Clean Air Act in the absence of specific carbon legislation from Congress. The EPA has promulgated two greenhouse gas regulations that apply to the Company’s generating facilities. In 2009, the EPA finalized a mandatory greenhouse gas emissions registry which requires the reporting of emissions. The EPA has also finalized a revision to the Prevention of Significant Deterioration (PSD) and Title V permitting rules which would require facilities that emit 75,000 tons or more of greenhouse gases a year to obtain a PSD permit for new construction or a significant modification of an existing facility. EPA's PSD and Title V permitting rules for GHG's were recently upheld by the US Court of Appeals for the District of Columbia. In April 2012, the EPA issued its proposed new source performance standards for greenhouse gases applicable to new construction. This proposed rule does not apply to existing sources, such as Vectren’s generating facilities. The EPA has not indicated when it intends to propose standards for existing sources.

Numerous competing federal legislative proposals have also been introduced in recent years that involve carbon, energy efficiency, and renewable energy. Comprehensive energy legislation at the federal level continues to be debated, but there has been little progress to date. The progression of regional initiatives throughout the United States has also slowed.

Impact of Legislative Actions & Other Initiatives is Unknown

If regulations are enacted by the EPA or other agencies or if legislation requiring reductions in CO2 and other greenhouse gases or legislation mandating a renewable energy portfolio standard is adopted, such regulation could substantially affect both the costs and operating characteristics of the Company’s fossil fuel generating plants, nonutility coal mining operations, and natural gas distribution businesses. At this time and in the absence of final legislation or rulemaking, compliance costs and other effects associated with reductions in greenhouse gas emissions or obtaining renewable energy sources remain uncertain. The Company has gathered preliminary estimates of the costs to control greenhouse gas emissions. A preliminary investigation demonstrated costs to comply would be significant, first with regard to operating expenses and later for capital expenditures as technology becomes available to control greenhouse gas emissions. However, these compliance cost estimates are based on highly uncertain assumptions, including allowance prices if a cap and trade approach were employed, and energy efficiency

31

targets. Costs to purchase allowances that cap greenhouse gas emissions or expenditures made to control emissions should be considered a cost of providing electricity, and as such, the Company believes such costs and expenditures would be recoverable from customers through Senate Bill 251.

Manufactured Gas Plants

In the past, the Company operated facilities to manufacture natural gas. Given the availability of natural gas transported by pipelines, these facilities have not been operated for many years. Under current environmental laws and regulations, those that owned or operated these facilities may now be required to take remedial action if certain contaminants are found above the regulatory thresholds at these sites.

In the Indiana Gas service territory, the existence, location, and certain general characteristics of 26 gas manufacturing and storage sites have been identified for which the Company may have some remedial responsibility. A remedial investigation/feasibility study (RI/FS) was completed at one of the sites under an agreed order between Indiana Gas and the IDEM, and a Record of Decision was issued by the IDEM in January 2000. The remaining sites have been submitted to the IDEM's Voluntary Remediation Program (VRP). The Company has identified its involvement in five manufactured gas plant sites in SIGECO’s service territory, all of which are currently enrolled in the IDEM’s VRP. The Company is currently conducting some level of remedial activities, including groundwater monitoring at certain sites.

The Company has accrued the estimated costs for further investigation, remediation, groundwater monitoring, and related costs for the sites. While the total costs that may be incurred in connection with addressing these sites cannot be determined at this time, the Company has recorded cumulative costs that it reasonably expects to incur totaling approximately $41.7 million ($23.2 million at Indiana Gas and $18.5 million at SIGECO). The estimated accrued costs are limited to the Company’s share of the remediation efforts and are therefore net of exposures of other potentially responsible parties (PRP).

With respect to insurance coverage, Indiana Gas has received approximately $20.8 million from all known insurance carriers under insurance policies in effect when these plants were in operation. SIGECO filed a declaratory judgment action against its insurance carriers seeking a judgment finding its carriers liable under the policies for coverage of further investigation and any necessary remediation costs that SIGECO may accrue under the VRP program and/or another site subject to a lawsuit that has been settled. In November 2011, the Court ruled on two motions for summary judgment, finding for SIGECO and against certain insurers on indemnification and defense obligations in the policies at issue. SIGECO has settlement agreements with all known insurance carriers and has recorded approximately $15.2 million of expected insurance recoveries.

The costs the Company expects to incur are estimated by management using assumptions based on actual costs incurred, the timing of expected future payments, and inflation factors, among others. While the Company’s utilities have recorded all costs which they presently expect to incur in connection with activities at these sites, it is possible that future events may require some level of additional remedial activities which are not presently foreseen and those costs may not be subject to PRP or insurance recovery. As of September 30, 2012 and December 31, 2011, respectively, approximately $4.8 million and $6.5 million of accrued, but not yet spent, costs are included in Other Liabilities related to both the Indiana Gas and SIGECO sites.

Rate & Regulatory Matters

Vectren South Electric Base Rate Filing

On December 11, 2009, Vectren South filed a request with the IURC to adjust its base electric rates. The requested increase in base rates addressed capital investments, a modified electric rate design that would facilitate a partnership between Vectren South and customers to pursue energy efficiency and conservation, and new energy efficiency programs to complement those currently offered for natural gas customers. The IURC issued an order in the case on April 27, 2011. The order provides for an approximate $28.6 million revenue increase to recover costs associated with approximately $325 million in system upgrades that were completed in the three years leading up to the December 2009 filing and modest increases in maintenance and operating expenses. The approved revenue increase is based on rate base of $1,295.6 million, return on equity of 10.4 percent and an overall rate of return of 7.29 percent. The new rates were effective May 3, 2011. The IURC, in its order, denied the Company’s request for implementation of the decoupled rate design, which is discussed further below. Addressing issues raised in the case concerning coal supply contracts and related costs, the IURC found that current coal contracts remain effective and that a prospective review process of future procurement decisions would be initiated.

32

Coal Procurement Procedures

Vectren South submitted a request for proposal in April 2011 regarding coal purchases for a four year period beginning in 2012. After negotiations with bidders, Vectren South reached an agreement in principle for multi-year purchases with two suppliers, one of which is Vectren Fuels, Inc. Consistent with the IURC direction in the electric rate case, a sub docket proceeding was established to review the Company’s prospective coal procurement procedures, and the Company submitted evidence related to its recent request for proposal (RFP) and those coal procurement procedures to the IURC in September 2011. In March 2012, the IURC issued its order in the sub docket. The order concluded that Vectren South’s 2011 RFP process resulted in prices at the lowest fuel cost reasonably possible. The IURC will continue to regularly monitor Vectren South’s procurement process in future fuel adjustment proceedings.

Vectren South Electric Fuel Cost Reduction

In the spring of 2011, Vectren South secured contracts for lower coal costs through a formal bidding process. This lower-priced contract coal started being delivered to Vectren’s power plants during 2012. On December 5, 2011 within the quarterly FAC filing, Vectren South submitted a joint proposal with the OUCC to reduce its fuel costs by accelerating into 2012 the impact of lower cost coal under new term contracts effective after 2012. The cost difference will be deferred to a regulatory asset and recovered over a six-year period without interest beginning in 2014. The IURC approved this proposal on January 25, 2012, with a positive impact to customer’s rates effective February 1, 2012. The deferred amount includes a reduction in the value of the coal inventory at December 31, 2011 of approximately $17.7 million to reflect existing coal inventory at the new, lower price. Deferrals related to coal purchases in 2012 have totaled approximately $24.7 million, bringing the total deferred balance as of September 30, 2012 to the expected level of $42.4 million. In addition to coal purchased under these contracts, Vectren South has also recently contracted with Vectren Fuels, Inc. to purchase lower priced spot coal. This spot purchase was found to be reasonable in a recent FAC order.

Vectren South Electric Demand Side Management Program Filing

On August 16, 2010, Vectren South filed a petition with the IURC, seeking approval of its proposed electric Demand Side Management (DSM) Programs, recovery of the costs associated with these programs, recovery of lost margins as a result of implementing these programs for large customers, and recovery of performance incentives linked with specific measurement criteria on all programs. The DSM Programs proposed are consistent with a December 9, 2009 order issued by the IURC, which, among other actions, defined long-term conservation objectives and goals of DSM programs for all Indiana electric utilities under a consistent statewide approach. In order to meet these objectives, the IURC order divided the DSM programs into Core and Core Plus programs. Core programs are joint programs required to be offered by all Indiana electric utilities to all customers, and include some for large industrial customers. Core Plus programs are those programs not required specifically by the IURC, but defined by each utility to meet the overall energy savings targets defined by the IURC.

On August 31, 2011 the IURC issued an order approving an initial three year DSM plan in the Vectren South service territory that complies with the IURC’s energy saving targets. Consistent with the Company’s proposal, the order approved, among other items, the following: 1) recovery of costs associated with implementing the DSM Plan; 2) the recovery of a performance incentive mechanism based on measured savings related to certain DSM programs; 3) lost margin recovery associated with the implementation of DSM programs for large customers; and 4) deferral of lost margin up to $1 million in 2011 associated with small customer DSM programs for subsequent recovery under a tracking mechanism to be proposed by the Company. On June 20, 2012, the IURC issued an order approving a small customer lost margin recovery mechanism, inclusive of all previous deferrals. This mechanism is an alternative to the electric decoupling proposal that was denied by the IURC in the Company's last base rate proceeding discussed earlier.

Vectren South Electric Dense Pack Filing

On September 14, 2011, Vectren South filed a petition with the IURC seeking recovery of and return on the capital investment in dense pack technology to improve the efficiency of its A.B. Brown Generating Station. This investment is expected to be approximately $32 million over the next two years, of which approximately $25.5 million has been invested to date. This technology is expected to allow the A.B. Brown units to run at least 5 percent more efficient, thereby burning less fuel, and reducing fuel costs and emissions of pollutants. In the Company’s base rate order issued in April 2011, the IURC authorized deferred accounting treatment associated with this investment. As a result of a subsequent filing by the Company seeking a

33

current recovery mechanism in lieu of the deferred accounting treatment, the IURC issued an order on July 11, 2012, denying the Company's request for a current recovery mechanism stating that dense pack technology does not qualify as advanced technology under the statute. Although the Company believes that the investment does meet the requirements of the statute that would have allowed for timely recovery, it does not plan to appeal the decision and will employ the deferred accounting treatment ordered in the Company's last base rate order discussed earlier.

Vectren North Reporting Location Consolidation Proceeding

Vectren North implemented a reporting location consolidation plan in 2011 and converted certain reporting locations into staging areas throughout the Vectren North territory. On May 26, 2011, the International Brotherhood of Electrical Workers Local 1393, United Steel Workers Locals 12213 and 7441 and others (the “Complainants”) filed a formal complaint with the IURC claiming that implementation of the consolidation plan by Vectren North endangers public safety and impairs Vectren North's ability to provide adequate, safe and reliable service. The Complainants asked the IURC to require Vectren North to reopen previously consolidated reporting locations and maintain and staff those locations. A hearing in this case was held in February 2012 and the Company is awaiting the issuance of an order.

Results of Operations of the Nonutility Group

The Nonutility Group operates in four primary business areas: Infrastructure Services, Energy Services, Coal Mining, and Energy Marketing. Infrastructure Services provides underground construction and repair. Energy Services provides performance contracting and renewable energy services. Coal Mining mines and sells coal. Energy Marketing markets and supplies natural gas and provides energy management services. There are also other legacy businesses that have invested in energy-related opportunities and services, real estate, and leveraged leases, among other investments. The Nonutility Group supports the Company’s regulated utilities pursuant to service contracts by providing natural gas supply services, coal, and infrastructure services. Nonutility Group earnings for the three and nine months endedSeptember 30, 2012 and 2011 follow:

Three Months Ended

Nine Months Ended

September 30,

September 30,

(In millions, except per share amounts)

2012

2011

2012

2011

NET INCOME (LOSS)

$

13.2

$

7.6

$

14.1

$

3.4

CONTRIBUTION TO VECTREN BASIC EPS

$

0.16

$

0.09

$

0.17

$

0.04

NET INCOME (LOSS) ATTRIBUTED TO:

Infrastructure Services

$

15.9

$

11.9

$

27.3

$

11.1

Energy Services

2.6

2.3

0.9

1.6

Coal Mining

(2.2

)

5.8

—

15.9

Energy Marketing

Vectren Source

—

(3.6

)

—

1.0

ProLiance

(2.4

)

(8.6

)

(13.5

)

(25.3

)

Other Businesses

(0.7

)

(0.2

)

(0.6

)

(0.9

)

Infrastructure Services

Infrastructure Services provides underground construction and repair services through wholly-owned subsidiaries Miller Pipeline and Minnesota Limited, which was acquired on March 31, 2011. Inclusive of holding company costs, earnings from Infrastructure Services' operations for the third quarter of 2012, were $15.9 million, compared to $11.9 million in the prior year's third quarter. During the nine months ended September 30, 2012, earnings were $27.3 million, compared to $11.1 million year to date in 2011. Both the quarter and year to date increases in earnings reflect increased demand across all infrastructure business areas. The year to date period and the early part of the third quarter also benefited from warm, dry weather aiding favorable construction conditions. Revenues year to date in 2012 were $449 million. These operations had year to date revenues in 2011 of $314 million, including $21 million from Minnesota Limited prior to its acquisition on March 31, 2011. While favorable weather may have caused some annual utility capital expenditure budgets to be advanced earlier in the year, construction activity has remained strong in 2012 and is expected to continue as utilities and pipeline operators replace their aging natural gas and oil pipeline infrastructure and as the demand for shale gas and oil infrastructure becomes more prevalent.

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As an example, Infrastructure Services was recently awarded a contract to construct an approximately 80 mile natural gas pipeline in the Bakken Shale area of North Dakota. It is expected this work will be completed by the end of the second quarter of 2013.

Acquisition of Minnesota Limited

On March 31, 2011, the Company purchased Minnesota Limited, Inc., excluding certain assets. Minnesota Limited is a specialty contractor focusing on transmission pipeline construction and maintenance; pump station, compressor station, terminal and refinery construction; gas distribution; and hydrostatic testing. Minnesota Limited is headquartered in Big Lake, Minnesota and the majority of its customers are generally located in the northern Midwest region. The purchase price was approximately $83.4 million and included $14.8 million of net working capital, $34.4 million of property plant and equipment and $39.4 million of intangible assets, including goodwill.

Energy Services

Energy Services provides energy performance contracting and renewable energy services through wholly-owned subsidiary Energy Systems Group, LLC (ESG). Inclusive of holding company costs, Energy Services earned $2.6 million during the third quarter of 2012, compared to earnings of $2.3 million in the prior year's third quarter. Energy Services' operations earned $0.9 million during the nine months ended September 30, 2012, compared to earnings of $1.6 million in 2011.

Results in 2012 reflect reduced revenues which indicate some near-term slowing in demand for performance contracting projects due to current budgetary constraints on municipal and school customers. The increase for the quarter is due to recognition of tax deductions associated with energy efficiency projects completed in 2011 in accordance with IRS guidance released in 2012. As of September 30, 2012, performance contracting backlog was $87 million, compared to $100 million on September 30, 2011. ESG placed three “build and own” anaerobic digester projects into service in 2012. ESG continues to add to its employee base and footprint to position it for long-term growth in this sector as the national focus on energy conservation, renewable energy, and sustainability continues given the expected rise in power prices across the country.

Coal Mining

Coal Mining owns mines that produce and sell coal to the Company’s utility operations and to third parties through its wholly-owned subsidiary, Vectren Fuels, Inc. (Vectren Fuels). Coal Mining, inclusive of holding company costs, operated at a loss of $2.2 million in the third quarter of 2012, compared to earnings of $5.8 million in 2011. Year to date in 2012, Coal Mining results are break even, compared to earnings of $15.9 million in the prior year. Results were anticipated to be lower in 2012 due to reduced pricing for customers associated with contracts that had price reopener clauses effective for 2012. However, results in 2012 have also been negatively impacted by softness in the overall coal market due primarily to the mild winter heating weather and the impact of low natural gas prices. In addition, results were further negatively impacted by production reductions to better match sales and higher mining costs at the Prosperity mine due to a thin coal seam and other unfavorable mining conditions. These increased costs offset favorable cost per ton results at the Oaktown mine during 2012. The cost environment is favorable at Oaktown but has also been impacted by the reduced production driven by lower demand. Coal sales year to date in 2012 were 3.2 million tons, compared to 4.0 million tons last year. Through the nine months ended September 30, 2012, Coal Mining revenues were $172 million, a $49 million decrease compared to 2011.

Vectren Fuels continues negotiations with a number of customers regarding sales in 2012 and beyond. In the third quarter, Vectren Fuels contracted for additional term sales of significant tons to be delivered in each of 2013, 2014, and 2015. Including fourth quarter spot sales, 2012 coal sales are now estimated at 4.4 million tons. The impact of reduced demand for coal is expected to result in a loss from Coal Mining operations for the year ended December 31, 2012. The Company is maintaining production at lower levels to more closely match the current demand. Longer term, the Company continues to believe that reduced coal volumes available from Central Appalachia due to increased regulation and the large number of scrubbers to be installed throughout the United States, including the Midwest, coupled with moderate increases in natural gas prices from the very low levels experienced during the first half of 2012, should drive stronger demand for Illinois Basin coal. Changes in market conditions or other circumstances could cause actual results to be materially different from these expectations.

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Coal Reserves

As of September 30, 2012, management estimates the Company’s total Illinois Basin coal reserves to be approximately 128 million tons. Of this amount, approximately 39 million tons are attributable to the second mine at the Company's Oaktown mining complex that has not yet been placed into service. Construction is substantially complete. Vectren Fuels continues to assess when to open the second Oaktown mine in relation to current market conditions for this higher quality coal and thus it is not expected the mine will open in 2012. However, once this mine is in production, Vectren Fuels underground mines are capable of producing about 7.5 million tons of coal per year.

Mine Safety Information

The Company, through Vectren Fuels, owns coal mines and related assets located in Indiana. The Company has retained independent third party contract mining companies to operate its coal mines. Five Star Mining LLC ("Five Star") is the contract mining company at the Prosperity underground mine and Black Panther Mining LLC ("Black Panther") is the contract mining company at the Oaktown underground mines. The contract mining companies are the mine “operator”, as that term is used in both the Federal Mine Safety and Health Act of 1977 (the “Mine Act”) and the Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010. All employees at the coal mines are hired, supervised, and paid by the contract mining companies. As the mine operator, the contract mining companies make all regulatory filings required by the MSHA. In most circumstances, however, the cost of fines and penalties assessed by MSHA are contractually passed through from the contract mining company to Vectren Fuels. The process of settling such claims can take years in certain circumstances. During the nine months ended September 30, 2012, the Company paid approximately $0.4 million related to assessments issued to the mine operators.

On April 30, 2012, Five Star received a citation referred to as an “imminent danger” citation for high levels of methane near one of the roof bolting machines operating in the Prosperity Mine. The machine was idled for approximately two hours while the methane levels were lowered by adjusting airflow near the equipment. Other mining operations continued during this period. No injuries or property damage resulted from the incident.

More detailed information about the Company’s mines, including safety-related data, can be found at MSHA’s website, www.MSHA.gov. Prosperity operates under the MSHA identification number 1202249; Oaktown 1 operates under the identification number 1202394; and Oaktown 2’s identification number is 1202418. Mine safety-related data included on the MSHA website is influenced by the size of the mine, the level of activity at the mine, and the mine inspector’s judgment, among other factors. These factors can impact the comparability of information from mine to mine and time period to time period. Given incidents at coal mines of other companies, a significant increase in the frequency and scope of MSHA inspections continues. In addition, both houses of Congress are considering new mine safety legislation. The Company is currently assessing the impact new laws and regulations may have on its investments.

Energy Marketing

ProLiance

ProLiance, a nonutility energy marketing affiliate of Vectren and Citizens, provides services to a broad range of municipalities, utilities, industrial operations, schools, and healthcare institutions located throughout the Midwest and Southeast United States. ProLiance’s customers include Vectren’s Indiana utilities and Citizens’ utilities. ProLiance’s primary businesses include gas marketing, gas portfolio optimization, and other portfolio and energy management services. Consistent with its ownership percentage, Vectren is allocated 61 percent of ProLiance’s profits and losses; however, governance and voting rights remain at 50 percent for each member. Therefore, the Company accounts for its investment in ProLiance using the equity method of accounting. On March 17, 2011, an order was received from the IURC providing for ProLiance’s continued provision of gas supply services to the Company’s Indiana utilities and Citizens Energy Group through March 2016.

Vectren Energy Marketing and Services, Inc (EMS), a wholly owned subsidiary, holds the Company’s investment in ProLiance. Within the consolidated entity, EMS is responsible for certain financing costs associated with ProLiance and is also responsible for income taxes and allocated corporate expenses related to the Company’s portion of ProLiance’s results. During the three months ended September 30, 2012 and 2011, EMS’ results related to the Company’s share of ProLiance’s losses, which include financing costs income taxes, and other holding company costs, were a loss of approximately $2.4 million, compared to a loss of $8.6 million in 2011. During the nine months September 30, 2012 and 2011, results at EMS related to

36

ProLiance were a loss of approximately $13.5 million, compared to a loss of $25.3 million in 2011. The smaller losses primarily reflect the reduction in fixed demand costs for both storage and transportation contracts, plus better optimization margins due to improved seasonal spreads and higher pipeline utilization rates.

Efforts to lower the cost of pipeline and storage demand costs continue. Through negotiations and by dropping some uneconomical contracts as they expire, ProLiance has lowered its pipeline transportation and storage costs to approximately $55 million for all of 2012, compared to $73 million in 2011. The projected annual demand costs in 2013 are approximately $45 million, or $10 million lower than 2012. In addition to these reductions, additional opportunities exist to renegotiate or drop contracts with annual demand costs of $12 million by 2015. Changes in market conditions or other circumstances could cause actual demand costs to be materially different from this expectation. At September 30, 2012, ProLiance had approximately $134 million of members' equity on its balance sheet, no long-term debt outstanding and borrowings of $38 million on its new $120 million credit facility, which became effective in May 2012.

For the three months ended September 30, 2012 and 2011, the amounts recorded to Equity in (losses) of unconsolidated affiliates related to ProLiance’s operations totaled a pre-tax loss of $3.0 million and $11.9 million, respectively. For the nine months ended September 30, 2012 and 2011, the amounts recorded to Equity in (losses) of unconsolidated affiliates related to ProLiance’s operations totaled a pre-tax loss of $17.1 million and $34.9 million, respectively.

Investment in Liberty Gas Storage

Liberty Gas Storage, LLC (Liberty), a joint venture between a subsidiary of ProLiance and a subsidiary of Sempra Energy (SE), is a development project for salt-cavern natural gas storage facilities. ProLiance is the minority member with a 25 percent interest, which it accounts for using the equity method. The project was expected to include 17 Bcf of capacity in its North site, and an additional capacity of at least 17 Bcf at the South site. The South site also has the potential for further expansion. The Liberty pipeline system is currently connected with several interstate pipelines, including the Cameron Interstate Pipeline operated by Sempra U.S. Gas & Power, and will connect area LNG regasification terminals to an interstate natural gas transmission system and storage facilities.

In late 2008, the project at the North site was halted due to subsurface and well-completion problems, resulting in an impairment charge related to the North site being recorded in 2009. ProLiance’s ability to meet the needs of its customers has not been, nor does it expect it to be, impacted. Approximately 12 Bcf of the storage at the South site, which comprises three of the four FERC certified caverns, is fully completed and tested. As a result of the issues encountered at the North site, Liberty requested and the FERC approved the separation of the North site from the South site. As of September 30, 2012 and December 31, 2011, ProLiance’s investment in Liberty approximated $34.9 million and $35.1 million, respectively.

Liberty received a Demand for Arbitration from Williams Midstream Natural Gas Liquids, Inc. (“Williams”) on February 8, 2011 related to a Sublease Agreement (“Sublease”) between Liberty and Williams at the North site. Williams alleges that Liberty was negligent in its attempt to convert certain salt caverns to natural gas storage and thereby damaged the caverns. Williams alleges damages of $56.7 million. Liberty believes that it has complied with all of its obligations to Williams, including properly terminating the Sublease. Liberty intends to vigorously defend itself and has asserted counterclaims substantially in excess of the amounts asserted by Williams. As such, as of September 30, 2012, ProLiance has no material reserve recorded related to this matter and this litigation has not materially impacted ProLiance's results of operations or statement of financial position.

Vectren Source

In the three months ended September 30, 2011, retail energy marketer Vectren Source, which was sold on December 31, 2011, operated at a seasonal loss of $3.6 million. Year to date in 2011 earnings were $1.0 million. Due to the seasonality of the retail gas marketing business and the mild weather, Vectren Source earned $2.8 million for the full year in 2011.

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Impact of Recently Issued Accounting Guidance

Other Comprehensive Income (OCI)

In 2011, the FASB issued new accounting guidance regarding the presentation of comprehensive income within financial statements. The new guidance will require entities to report components of comprehensive income in either (1) a continuous statement of comprehensive income or (2) two separate but consecutive statements. Under the two-statement approach, the first statement would include components of net income, which is consistent with the income statement format used today, and the second statement would include components of OCI. The guidance does not change the items that must be reported in OCI. The new guidance is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011 and retrospective application is required. The Company adopted this guidance, as amended for condensed quarterly reporting, for the quarterly reporting period ended March 31, 2012 by reporting comprehensive income as required.

Goodwill Testing

In September 2011, the FASB issued new accounting guidance regarding testing goodwill for impairment. The new guidance will allow the Company an option to first assess qualitative factors to determine whether it is necessary to perform the two-step quantitative goodwill impairment test. Using the new guidance, the Company no longer would be required to calculate the fair value of a reporting unit unless the Company determines, based on that qualitative assessment, that it is more likely than not that its fair value is less than its carrying amount. The Company considered this option during its quarterly reporting period ended March 31, 2012 and concluded the continuation of the use of a quantitative approach is appropriate.

Fair Value Measurement and Disclosure

In May 2011, the FASB issued accounting guidance to improve the comparability of fair value measurements presented and disclosed in financial statements prepared in accordance with U.S. GAAP and International Financial Reporting Standards (IFRS). The amendments are not intended to change the application of the current fair value requirements, but to clarify the application of existing requirements. The guidance does change particular principles or requirements for measuring fair value or disclosing information about fair value measurements. To improve consistency, language has been changed to ensure that U.S. GAAP and IFRS fair value measurement and disclosure requirements are described in the same way. The Company adopted this guidance for its quarterly reporting period ended March 31, 2012. The adoption of this guidance did not have a material impact on our financial position, results of operations or cash flows.

The Company’s common stock dividends are primarily funded by utility operations. Nonutility operations have demonstrated profitability and the ability to generate cash flows. These cash flows are primarily reinvested in other nonutility ventures, but are also used to fund a portion of the Company’s dividends, and from time to time may be reinvested in utility operations or used for corporate expenses.

The credit ratings of the senior unsecured debt of Utility Holdings and Indiana Gas, at September 30, 2012, are A-/A3 as rated by Standard and Poor's Ratings Services (Standard and Poor’s) and Moody’s Investors Service (Moody’s), respectively. The credit ratings on SIGECO's secured debt are A/A1. Utility Holdings’ commercial paper has a credit rating of A-2/P-2. The current outlook of both Moody’s and Standard and Poor’s is stable. A security rating is not a recommendation to buy, sell, or hold securities. The rating is subject to revision or withdrawal at any time, and each rating should be evaluated independently of any other rating. Standard and Poor’s and Moody’s lowest level investment grade rating is BBB- and Baa3, respectively.

The Company’s consolidated equity capitalization objective is 45-55 percent of long-term capitalization. This objective may have varied, and will vary, depending on particular business opportunities, capital spending requirements, execution of long-term financing plans, and seasonal factors that affect the Company’s operations. The Company’s equity component was 49 percent and 47 percent of long-term capitalization at September 30, 2012 and December 31, 2011, respectively. Long-term capitalization includes long-term debt, including current maturities and debt subject to tender, as well as common shareholders’ equity.

Both long-term and short-term borrowing arrangements contain customary default provisions; restrictions on liens, sale-leaseback transactions, mergers or consolidations, and sales of assets; and restrictions on leverage, among other restrictions. Multiple debt agreements contain a covenant that the ratio of consolidated total debt to consolidated total capitalization will not exceed 65 percent. As of September 30, 2012, the Company was in compliance with all debt covenants.

Available Liquidity in Current Credit Conditions

The Company’s A-/A3 investment grade credit ratings have allowed it to access the capital markets as needed. The Company anticipates funding future capital expenditures and dividends principally through internally generated funds. Available liquidity has been enhanced by the extension of bonus depreciation legislation. However, the resources required for capital investment remain uncertain for a variety of factors including pending legislative and regulatory initiatives involving gas pipeline modernization; coal mine safety; and expanded EPA regulations for air, water, and fly ash. In addition, the Company may expand its businesses through acquisitions and/or joint venture investment. The timing and amount of such investments depends on a variety of factors, including the availability of acquisition targets and available liquidity. The Company plans to enhance its liquidity as needed by accessing the capital markets. The Company may also consider disposing of certain assets, investments, or businesses to enhance or accelerate internally generated cash flow.

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Consolidated Short-Term Borrowing Arrangements

At September 30, 2012, the Company has $600 million of short-term borrowing capacity, including $350 million for the Utility Group and $250 million for the wholly owned Nonutility Group and corporate operations. As reduced by borrowings currently outstanding, approximately $250 million million was available for the Utility Group operations and approximately $34 million was available for the wholly owned Nonutility Group and corporate operations. On November 1, 2012, Vectren Capital entered into a $100 million three year term loan agreement. The proceeds from this debt transaction were used to repay short-term borrowings, and as a result, free up capacity on the $250 million credit facility. Both Vectren Capital’s and Utility Holdings’ short-term credit facilities were renewed in November 2011 and are available through September 2016. These facilities are used to supplement working capital needs and also to fund capital investments and debt redemptions until financed on a long-term basis. Liquidity was increased by the $100 million Utility Holdings debt issuance in February 2012, the net proceeds of which were used to repay short-term indebtedness. Nonutility long-term debt totaling $35 million matured on April 25, 2012 and was replaced with short-term borrowings. Additional nonutility long-term debt of $25 million is to mature on December 15, 2012 and in the near term is expected to be replaced with short-term debt.

The Company has historically funded the short-term borrowing needs of Utility Holdings’ operations through the commercial paper market and expects to use the Utility Holdings short-term borrowing facility in instances where the commercial paper market is not efficient. Following is certain information regarding these short-term borrowing arrangements.